Potentials of sector coupling for decarbonisation : assessing regulatory barriers in linking the gas and electricity sectors in the EU : final report.
Date: 2019-12-17
Institutions: Directorate-General for Energy
Subjects: carbon capture and storage, clean technology, electrical energy, energy grid, gas, regulation (EU), renewable energy, report

Potentials  of  sector  coupling 
for decarbonisation - Assessing 
regulatory  barriers  in  linking 
the  gas  and  electricity  sectors 
in the EU 
- Final report 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
This study was carried out for the European Commission by Frontier Economics, 
together with CE Delft and THEMA Consulting Group, as part of the COWI Consortium. 

Frontier Economics 

Christoph Riechmann 
David Bothe 
Catherine Galano 
Vikram Balachandar 
Theresa Steinfort 

CE Delft 

Bettina Kampman 
Reinier van der Veen  
Thijs Scholten  
Anouk van Grinsven 

THEMA Consulting Group 

Åsmund Jenssen 
Adrian Mekki 

DISCLAIMER 

This study has been prepared for the European Commission by the above consortium of consultants. It reflects 
the views only of the authors. These views have not been adopted or in any way approved by the Commission 
and should not be relied upon as a statement of the Commission’s or DG ENER’s views. The results of this 
study do not bind the Commission in any way. The Commission does not guarantee the accuracy of the data 
included in the study. Neither the Commission nor any person acting on the Commission’s behalf may be held 
responsible for the use which may be made of the information contained therein.  

EUROPEAN COMMISSION 

Directorate-General for Energy 
Directorate B — Internal Energy Market 
Unit B2 — Wholesale Markets; Electricity & Gas 

Contact: Zsuzsanna Szeles and Colin Kuehnhanss 

E-mail: Zsuzsanna.SZELES@ec.europa.eu; Colin.KUEHNHANSS@ec.europa.eu  

European Commission 

B-1049 Brussels 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Potentials  of  sector  coupling 
for decarbonisation - Assessing 
regulatory  barriers  in  linking 
the  gas  and  electricity  sectors 
in the EU 
- Final report 

2019 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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MJ-01-18-845-EN-N 

ISBN 978-92-79-91803-2 
doi:10.2833/000080 

Luxembourg: Publications Office of the European Union, 2019 

© European Union, 2019 

Reuse is authorised provided the source is acknowledged. The reuse policy of European Commission 
documents is regulated by Decision 2011/833/EU (OJ L 330, 14.12.2011, p. 39).  

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table of Contents 

1  Executive Summary .................................................................. 4 

2  Acronyms .............................................................................. 20 

3  Introduction ........................................................................... 21 

3.1  Objective.............................................................................................21 

3.2 

Structure of this report .........................................................................21 

3.3  Overview of the future energy system and the role of gas .........................22 

3.3.1 

3.3.2 

3.3.3 

3.3.4 

The future EU energy system ............................................................22 

The role of gases and sector coupling and implications for infrastructure 25 

Linkages between energy carriers......................................................26 

Implications for policy ......................................................................28 

3.4  Definitions and scope ............................................................................29 

4  Methodology for Identifying Regulatory Barriers and Solutions ...... 31 

4.1  Methodology of regulatory barriers and gaps analysis ...............................31 

4.1.1 

4.1.2 

Definition of Barriers ........................................................................31 

Methodological approach for identifying barriers ..................................32 

4.2  Methodology to identify and assess solutions ...........................................36 

4.2.1 

4.2.2 

4.2.3 

Identification of solutions .................................................................36 

Assessment criteria .........................................................................36 

translating assessment criteria into recommendations .........................38 

5  List of barriers and solutions for short-listed barriers ................... 39 

5.1  Relative  immaturity  of  sector  coupling  and  renewable  and  low-carbon  gases 
technologies ..........................................................................................43 

5.1.1 

5.1.2 

5.1.3 

5.1.4 

5.1.5 

5.1.6 

5.1.7 

5.1.8 

Lack of internalisation of positive externalities from innovation / learning .. 
 ................................................................................................44 

Lack of liquid market for feedstock (biomass) .....................................49 

Lack of know-how / engagement from players controlling process inputs49 

First  mover  disadvantage  -  high  infrastructure  connection  costs  including 
‘deep’ costs ....................................................................................49 

Behavioural or informational barriers to acceptance/switching for household 
consumers ......................................................................................52 

Barriers to switching in the industry sector .........................................53 

Affordability issues ..........................................................................53 

Sector-  and  technology-specific  targets  biasing  choice  of  technologies  by 
end consumers ...............................................................................54 

5.1.9 

Uncertain ability to monetise renewable / low-carbon characteristics .....55 

5.1.10 

Absence of a harmonized definition of sustainable investment and the role 
of sector coupling therein .................................................................56 

2019 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.2 

5.2.1 

5.2.2 

5.2.3 

5.2.4 

5.2.5 

5.2.6 

Unlevel playing field due to sector- and technology-specific tariffs and levies .. 
 ..........................................................................................................56 

Power-to-gas facing end-user taxes on electricity ................................57 

Sunk costs and dismantling costs of gas infrastructure weighing on gas grid 
fees ...............................................................................................59 

Some forms of CCS (non-pipeline CO2 transport) liable under ets ..........62 

Conventional hydrogen production on the carbon leakage list ...............62 

Distorted competition for inputs ........................................................63 

Distortions in choice from taxes and other policy actions ......................64 

5.3 

Focus on natural gas in infrastructure regulation ......................................64 

5.3.1 

5.3.2 

5.3.3 

5.3.4 

5.3.5 

5.3.6 

5.3.7 

Uncertain  access  to  infrastructure  due  to  uncertain  or  inadequate  quality 
standards .......................................................................................65 

Lack of (injection) charging methodology ...........................................67 

Incentive  for  grid  operators  to  focus  on  gases  compatible  with  their 
infrastructure ..................................................................................68 

Lack of clear rules / compensation for interruption of gas injection ........71 

Uncertainty  on  the  regulation  of  hydrogen  (&  other  new  gases) 
infrastructure ..................................................................................74 

Restrictions on TSOs’ ability to operate infrastructure for other gases ....75 

Overly  rigid  calorific  value  requirements  for  billing  disadvantaging  some 
gases .............................................................................................75 

5.3.8 

London Protocol bans CO2 exports .....................................................76 

5.4 

Uncoupled and uncoordinated infrastructure planning ...............................76 

5.4.1 

5.4.2 

5.4.3 

Risk that suitable storage will not be available ....................................77 

Insufficient  co-ordination  on  future  use  of  transmission  and  distribution 
infrastructure:  geographic  mapping  of  production,  and  implications  for 
connections and infrastructure adaptation ..........................................78 

Insufficient co-ordination on future use of electricity and gas transmission 
infrastructure – and aligned operator incentives ..................................80 

5.5 

Risk for interoperability across markets and borders .................................82 

5.5.1 

5.5.2 

5.5.3 

5.5.4 

5.5.5 

5.5.6 

Possible lack of intra-EU co-ordination on standards ............................82 

Access to hub trading for gases injected at distribution level .................83 

Risk of lack of liquid market for sale of heterogenous gases ..................84 

Unharmonised national policies distorting trade ...................................85 

Lack of coherent cross-border framework for decommissioning .............86 

Different timescales for electricity / gas markets .................................88 

6  Summary of Recommendations ................................................ 89 

6.1 

6.2 

6.3 

6.4 

6.5 

2019 

Climate and renewable policy and support for innovation ..........................90 

Regulatory toolbox to address cost recovery issues ..................................90 

Fit for purpose market design and charging arrangements .........................91 

Clarity on access to infrastructure ..........................................................91 

Co-ordinated infrastructure planning and decommissioning........................92 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Appendices 

Regulatory  barriers  and  gaps:  detailed  information  on  the 
93 
research methodology and tools 

Regulatory barriers and gaps: overview of the major findings of 
94 
the country-based research 

 Detailed information on solutions assessment 

100 

2019 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1  EXECUTIVE SUMMARY 

STUDY OBJECTIVE 

Frontier  Economics  (‘Frontier’),  together  with  CE  Delft  and  THEMA  Consulting  Group 
(‘THEMA’),  as  part  of  the  COWI  Consortium  (hereafter  “the  consortium”)  have  been 
appointed by the European Commission to carry out a study on the integration of the 
EU gas and electricity sectors - assessing regulatory barriers (ENER/B2/2018-260). 

This report presents the results of the consortium’s assessment1 of regulatory barriers 
and gaps preventing closer linking of the EU gas and electricity sectors (both in terms 
of  their  markets  and  infrastructure)  and  hindering  the  deployment  of  renewable  and 
low-carbon gases. 

The main objectives of this study are: 

 

 
 
 

 

to provide a vision of the future energy system for the EU (in 2030 and in 2050) 
in which full decarbonisation of the energy system is achieved; 
to discuss the future role of gases in this system;  
to identify the potential technologies necessary for these developments;  
to identify regulatory barriers and gaps for the effective and efficient deployment 
of these technologies; and 
to discuss possible solutions and policy recommendations.  

THE FUTURE EU ENERGY SYSTEM, THE ROLE OF GASES AND THE 
CONCEPT OF SECTOR COUPLING  

In the coming decades, the EU energy system needs to change dramatically to make 
the transition to a decarbonised energy system. This transition is necessary to achieve 
the  EU’s  2030  climate  targets  as  well  as  the  EU’s  commitments  under  the  Paris 
Agreement, which aim to limit the average global temperature rise to well below 2°C.  
While it is difficult to project with certainty exactly what this means for the EU energy 
system by 2050, some key themes emerge from recent studies.  

One insight from these studies is that decarbonisation of the energy system is expected 
to be associated with an increasing level of integration of different energy carriers, in 
particular  gases,  electricity  and  heat.  For  the  purpose  of  this  study,  we  understand 
sector  coupling  as  linking  the  EU  electricity  and  gas  sectors,  both  in  terms  of  their 
markets and infrastructure.2 

1 We note that this study is based on qualitative research. In particular, and as described 
further  in  the  main  body  of  the  report,  the  analysis  is  based  on  a  review  of  existing 
quantitative  and  qualitative  evidence  in  relation  to  the  current  and  future  energy 
system. 
2  There  are  other  ways  in  which  the  electricity  and  gas  sectors  could  be  increasingly 
integrated in the future. These include, for example, the use of biomethane in power 
generation  and  the  flexible  (‘smart’)  use  of  electricity  and  gas  heating  depending  on 
price,  whether  in  individual  buildings  (in  ‘hybrid’  heat  pumps)  or  in  district  heating 
networks.  

2019 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
                                           
 
 
 
A  key  driver  behind  this  is  the  reduction  in  the  cost  of  producing  electricity  from 
renewable sources in recent years. Continued cost reductions could provide a business 
case for using this electricity to produce gases such as hydrogen or methane in a carbon 
neutral way.  

Another key driver of sector coupling, and the deployment of renewable and low-carbon 
gases more generally (including biogas and biomethane), is the potential cost saving to 
be realised from their use in a decarbonised energy system. While overall final energy 
demand is expected to decrease due to energy efficiency, consumption of electricity is 
expected  to  increase.  This  demand  is  expected  to  be  met  by  increasing  shares  of 
renewable electricity.  

However,  much  of  the  new  renewable  electricity  generation  capacity  will  be  from 
intermittent sources (such as solar and wind) and may not typically be located close to 
either load centres or existing network connections. It will therefore be important to find 
cost-effective storage and transport solutions for this renewable energy.  

The case for renewable and low-carbon gases arises  from the fact that they could be 
transported and stored at lower cost than electricity, by making use of existing storage 
and transport infrastructure. Their use may also avoid potentially costly and distruptive 
changes to end-use appliances.  

The extent to which gases will be used in the future is uncertain. It will depend on a 
range of factors, including: 

  The  availability  of  alternative  flexibility  options  in  the  energy  system  –  in 
particular,  considering  the  role  the  gas  system  currently  plays  in  the  energy 
system in helping to meet seasonal fluctuations in energy demand, other sources 
of  seasonal  flexibility  such  as  generation  with  carbon  capture  and  storage  or 
seasonal heat storage; 

  Developments in the relative costs of gas and electricity end-use appliances; and 
  The role of policy in steering outcomes.  

Exactly which gases will be used in the future is also uncertain.3 The use of natural gas 
may potentially increase in the transition to replace more polluting fuels (i.e. to 2030) 
but should eventually largely be phased out by 2050. However, different renewable and 
low-carbon gases (for example biomethane, hydrogen and synthetic methane) could all 
play a role in the future. This uncertainty is exposed by the varying roles that different 
scenarios foresee for different types of gases (summarised in Figure 1 below). It is also 
possible  that  some  gases  may  feature  more  strongly  in  some  Member  States  than 
others.  

3  This  study  mentions  a  wide  range  of  gases  that  are  likely  to  play  a  role  in  the 
decarbonisation  of  the  EU  energy  supply  of  the  coming  decades.  A  list  of  relevant 
definitions has been developed (adhering to the definitions included in Article 2 of the 
Renewable Energy Directive recast (RED II)), and is set out in section 3.4 of this report. 

Page 5 

 
 
 
                                           
 
 
Figure 1 EU demand for gaseous fuels, in 2015, forecast for 2030, baseline for 2050 and different 
decarbonisation scenarios for 2050 developed for the EU 2050 strategy 

Source:  European  Commission  (2018)  “A  Clean  Planet  for  all,  A  European  strategic  long-term  vision  for  a 
prosperous, modern, competitive and climate neutral economy”, COM(2018) 773 final. 

As well as increased gas and electricity sector coupling, large-scale deployment of the 
technologies that are part of the hydrogen and methane supply chains will also result in 
linkages between natural gas, hydrogen and methane. This is illustrated in Figure 2.  

Page 6 

050100150200250300350400MtoeNatural gasBiogas and waste gasSynthetic methaneHydrogen 
 
 
Figure 2 
gas, hydrogen and methane  

High-level overview of linkages between gases for energy use in 2050: Natural 

Figure 2 shows, for example, that: 

  Methane and hydrogen supply chains might be linked either via reforming of 
natural  gas,  by  conversion  of  hydrogen  into  synthetic  methane  or  through 
blending in the gas network;  

  A  common  feedstock  (biomass)  could  link  hydrogen  production  and 

biomethane production; and 

  Hydrogen, methane and CO2 supply chains could be linked through possible 

competition for gas storage capacity.  

The findings from our literature review have a range of implications for gas infrastructure 
and  storage  needs  and  policy.  While  the  precise  impacts  differ  significantly  between 
scenarios applied in recent literature, a number of themes emerge: 

  The  first  is  the  importance  of  continued  innovation  and  learning  in 

technologies that are currently less mature. 

  The second is the variety of technological approaches to renewable and low-
carbon gases and sector coupling technologies, highlighting the importance 
of  a  level  playing  field  for  gases  (compared  to  other  energy  carriers)  and 
between different gases (especially once such technologies are no longer in 
the transition phase), as well as openness to potential new technologies. 
  The third is that, while the use of natural gas is expected to be largely phased 
out by 2050, new gases will begin to flow in increasing quantities in existing 
infrastructure. As a result, the focus of infrastructure regulation will need to 
shift from natural gas to a  variety  of different  (low-carbon and  renewable) 
gases. 

  The fourth is that growing interlinkages between energy carriers and between 
transmission  and  distribution  systems  mean  that  co-ordination  in  system 
planning and operation will become increasingly important. 

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HydrogenfrombiomassMethanepipeline networkMethanevehiclesMethanepower plantMethaneboilerSyntheticmethaneproductionBiomethaneproductionWater electrolysisHydrogenpipeline networkHydrogenvehiclesHydrogenboilerHydrogenpower plantNatural gas reforming= CO2= H2= methane= ‘hythane’= competingforlocationsOtherCO2-sourcesCO2storageMethanestorageHydrogenstorage 
 
 
  The  fifth  is  that  different  countries  or  regions  may  adopt  different 
technological approaches. This suggests that attention needs to be paid  to 
how  to  ensure  that  different  gases  can  co-exist  both  within  and  between 
countries and regions and that interoperability and functioning markets are 
enabled.  

REGULATORY BARRIERS AND GAPS 

For  the  purposes  of  this  study,  regulation  is  defined  as  encompassing  the  legal 
framework at the EU or Member State level, acts of regulatory bodies and agencies as 
well  as  administrative  practice.  Regulation  (or  the  absence  thereof)  is  considered  to 
contribute  to  potential  barriers  to  sector  coupling  and  renewable  and  low-carbon  gas 
technologies  if  it  threatens  either  a  level  playing  field  between  technologies  or  the 
development  of  innovative  technologies.  Based  on  this  definition,  the  absence  of 
regulation  may  also  constitute  a  barrier.  The  study  therefore  also  covers  regulatory 
gaps.      

To identify possible barriers and gaps, we drew on a range of sources, including country-
based research into regulatory framework in a sample of Member States and input from 
stakeholders. The result was a ‘long list’ of potential barriers which is presented in this 
report.  From  this  ‘long  list’,  we  developed  a  ‘short  list’  of  barriers  for  which 
recommendations are provided.  

Figure 3 provides an overview of the barriers and gaps identified.  These are grouped 
into five categories: 

  A  first  group  includes  barriers  related  to  the  immaturity  of  the  relevant 

technologies.  

  A second group encompasses issues arising from technology- and sector-
specific  regulations  which  may  be  inadequate  in  the  emerging  sector-
coupled energy market.  

  The third and fourth barrier groups focus on infrastructure.  

o  Barriers  in  group  three  arise  from  the  transition  of  infrastructure 
from  being  used  for  natural  gas  to  being  potentially  used  by  a 
multitude of gas types. 

o  Group  four  focusses  on  issues  linked  to  the  increasing  need  of 
interlinkage between the electricity and gas sectors deploying 
sector-coupling technologies. 

  A fifth group concerns the interoperability between different markets. 

Within each group, we find that barriers and gaps pertain either to: 

  The transition phase, during which the costs of relevant technologies are 

expected to continue to reduce as their uptake increases; or 

  The  steady state,  i.e.  the  barriers  and  gaps  are  expected  to  prevail even 

when the relevant technologies have reached maturity.  

The full list of barriers and gaps identified as part of this study, organised in the five 
categories described above, is displayed in Figure 3 below. 

Page 8 

 
 
Overview of barriers and gaps preventing closer co-ordination (‘sector coupling’) 
Figure 3 
between the EU gas and electricity sectors and hindering the deployment of renewable and low-
carbon gases  

Source: Frontier Economics 

Below we summarise the short-listed barriers in each category. Further detail, including 
on the barriers not on the short list, is included in the main body of the report.  

Page 9 

 
 
 
Relative immaturity of relevant technologies 

Two barriers from this category have been retained in the short list. 

  Lack  of  internalisation  of  positive  externalities  from  innovation  / 
learning: Knowledge and learning from early stage R&D and deployment will 
not only benefit the stakeholders undertaking and financing the investment 
but  will  spread  more  widely.  As  a  result,  although  the  costs  borne  by  the 
developer may be lower than the benefit to society (and thus an innovation 
in the public interest),  they could be higher than the benefit the individual 
developer can retrieve.  This may cause underinvestment in renewable and 
low-carbon gas technologies.  

  First  mover  disadvantage  –  high  infrastructure  connection  costs 
including  ‘deep’  costs:  Depending  on  connection  charging  rules  for  low-
carbon and renewable  gases production sites,  the first connecting site in a 
region  could  bear  high  connection  costs,  including  a  share  of  the  cost  of 
required  infrastructure  reinforcement  that  will  then  go  on  to  serve  to 
transport gases produced at other sites that connect subsequently.  This can 
deter the first site from connecting in the first place. This may in turn cause 
underinvestment in renewable and low-carbon gas technologies.  

Unlevel playing field due to sector- and technology-specific tariffs and 
levies 

Two barriers from this category have been retained on the short list. 

  Power-to-gas  facing  end-user  taxes  on  electricity:  Power-to-gas 
facilities  may  be  treated  as  end  consumers  and  face  electricity  input  costs 
that include end-user taxes and levies. This includes cases where these taxes 
and  levies  are  not  reflecting  forward-looking  costs  incurred  on  the  system 
due to the presence of these facilities (i.e. that are not ‘cost-reflective’), but 
instead are intended purely to recover costs, such as the cost of supporting 
renewable  energy  sources.  There  is  a  risk  that  the  recovery  of  taxes  and 
levies  from  power-to-gas  facilities  curbs  investment  in  this  technology 
relative to the level of investment that would have prevailed if those facilities 
only faced forward-looking costs. This would therefore preclude the system 
from benefiting from this technology. In particular, there is a risk of distortion 
of the level playing field between synthetic gases (that rely on electricity from 
the public system)  and  other renewable gases  such as biomethane, as the 
latter’s input costs are not significantly increased by end-consumer taxes and 
levies.   

  Sunk costs and dismantling costs of gas infrastructure weighing on 
gas  grid  fees:  With  the  expectation  of  declining  volumes  of  (natural)  gas 
transported, average infrastructure tariffs could be expected to increase to 
ensure recovery of  sunk investment costs. The risk is that this incentivises 
switching away from gas to other energy carriers to a degree that might not 
be cost effective from a societal perspective (because the increase in tariffs 
would  not  reflect  cost  causation,  but  the  recovery  of  legacy  costs). 
Additionally,  any  dismantling  costs  may  be  borne  by  low-carbon  and 
renewable gases consumers because of the common energy carrier, despite 
the fact that the infrastructure being dismantled  (or at least underutilised) 
was not built for them. 

Page 10 

 
 
 
Focus on natural gas in infrastructure regulation 

Five barriers from this category have been retained on the short list. 

  Uncertain  access  to  infrastructure  due  to  uncertain  or  inadequate 
quality standards: Many technologies may only be viable for developers if 
the  produced  gases  can  be  transported  and  stored.  But  quality  standards, 
developed  in  a  context  where  the  only  broadly  established  gas  type  was 
natural gas, currently impose restrictive conditions or limits. The market and 
investors face uncertainty on the extent to which injection will be possible for 
various  types  of  low-carbon  and  renewable  gas.  While  norms  have  been 
adopted  in  relation  to  biomethane  in  several  countries,  we  find  ongoing 
widespread uncertainty, e.g. on the allowed hydrogen blend. This is in part 
due  to  a  lack  of  evidence  regarding  technical  feasibilities  (though 
investigations are underway) and creates uncertainty for developers.  

  Lack  of  (injection)  charging  methodology:  Injection  of  renewable  and 
low-carbon gases at the distribution level is not covered by the existing EU-
level  network  charging  methodology.  Uncertainty  on  the  charging 
methodology  makes  it  difficult  for  potential  technology  developers  and 
network operators to anticipate future costs. 

  Incentive for grid operators to focus on gases compatible with their 
existing  infrastructure:  Grid  operators  face  a  number  of  incentives  that 
may bias them to facilitate access to the network for those gases that are 
compatible  with  their  current  infrastructure.  This  may  manifest  itself  in  a 
number  of  ways,  for  example  in  the  framework  for  connections.  This  may 
hinder  the  level  playing  field  between  different  renewable  and  low-carbon 
gases.  Existing  provisions  in  Directive  (EU)  2018/2001  of  the  European 
Parliament and of the Council of 11 December 2018 on the promotion of the 
use of energy from renewable sources (‘RED II’) and Directive 2009/73/EC 
of  the  European  Parliament  and  of  the  Council  of  13  July  2009  concerning 
common rules for the internal market in natural gas and repealing Directive 
2003/55/EC (‘the Gas  Directive’) may provide some degree of reassurance 
for  developers  of  renewable  gases  that  Member  States  will  take  actions  to 
facilitate  their  access  to  the  gas  system.  However,  it  is  not  clear  how  the 
provisions of the Gas Directive would apply to (non-renewable) low-carbon 
gases. And they do not specifically address issues related to network operator 
incentives. 

  Lack of clear rules / compensation for gas interruption/ curtailment:, 
In contrast to the electricity system, physical congestion has been relatively 
rare in the gas system. However, this may change in the energy transition 
due  to  the  increasing  role  of  low-carbon  and  renewable  gases  located  at 
distribution grid level, where fewer flexibility options may exist. This may be 
mitigated  by  making  investments  that  enable  flows  from  distribution  to 
transmission  level,  where  there  is  more  flexibility.  However,  this  may  not 
always  be  efficient  and  some  congestion  management  may  be  required  at 
distribution level. Given the importance of a high utilisation rate for typically 
capital-intensive  technologies,  developers  of  renewable  and  low-carbon 
gases will want to have clarity on how congestion will be managed. 

  Uncertainty on the regulation of hydrogen (& other  innovative new 
gases)  infrastructure:  While  the  Gas  Directive  sets  out  clear  rules  for 
unbundling,  third-party  access  and  tarification,  it  is  not  clear  how  these 
provisions  might  apply  to  gases  other  than  natural  gas,  biogas  and  gas 
produced  from  biomass.    This  uncertainty  may  cause  investors  to  abstain 
from investments into hydrogen or other innovative gases. 

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Uncoupled and uncoordinated infrastructure planning 

Three barriers from this category have been retained on the short list. 

  Risk that suitable storage will not be available:  Gas storage operators 
may  be  unable  to  predict  to  what  extent  there  will  be  a  technical  or 
commercial requirement for gas storage in the future energy system. Future 
gas demand is uncertain and storage facilities or the pipelines connecting the 
facility  may  not  be  technically  suitable  for  different  types  of  future  gases. 
Storage  operators  may  therefore  decide  to  stop  operating,  which  risks 
inefficiency  from  a  societal  perspective  if  the  flexibility  from  storage  is 
needed.  

  Insufficient  co-ordination  on  future  use  of  transmission  and 
distribution  infrastructure  (geographic  mapping  of  production,  and 
implications  for  connections  and  infrastructure  adaptation):  In  the 
long run, the optimal design of the gas system will depend on the least cost 
options to facilitate injection and transport of gases produced from least cost 
technologies.  This  may  involve  significant  changes  in  the  infrastructure 
design, such as enabling reverse flows or investment into additional capacity 
of the network itself to store gas. Optimising the long run design of the gas 
system  would  require  coordination  between  distribution  and  transmission 
level planning. 

  Insufficient  co-ordination  on  future  use  of  electricity  and  gas 
transmission  infrastructure  –  and  aligned  operator  incentives:  In  a 
world  of  growing  interlinkages  between  infrastructure  for  electricity  and 
gases, the least cost network infrastructure may only be designed and built 
if it is planned jointly by electricity and gas infrastructure operators (at both 
transmission and distribution level). 

Risk for interoperability across markets and borders 

Two barriers from this category have been retained on the short list. 

  Risk of lack of liquid market for sale of heterogenous gases: Given the 
heterogeneity in technologies and gases that may be deployed to achieve the 
decarbonisation of the energy sector, there is a risk of fragmentation of the 
gas market into different products and different regions. This may jeopardise 
the  (generally  strong)  liquidity  in  the  gas  market,  resulting  in  increasing 
transaction costs for market participants. 

  Lack 

of 

coherent 

investment 

cross-border 

framework 
decommissioning: As set out above, falling (natural) gas demand may lead 
to TSOs decommissioning some gas infrastructure. There is a risk that, while 
perhaps  cost-effective  from  an  individual  Member  State  perspective,  such 
decommissioning  may  be  inefficient  from  an  EU-wide  perspective  if 
infrastructure (interconnectors or other pipelines) benefits multiple Member 
States. A separate but related issue is that if Member States bear the entire 
cost  of  decommissioning  assets  within  their  territory  (and  these  costs  are 
recovered from gas users), the resulting tariffs may incentivise an inefficient 
switch away from gas (as described above under the barrier ‘sunk costs and 
dismantling costs of gas infrastructure weighing on gas grid fees’). 

Page 12 

 
 
 
Summary 

Figure 4 below summarises how the short-listed barriers and gaps described above map 
to different aspects of the energy policy and regulatory framework.  

Figure 4 Summary of regulatory barriers and gaps identified 

Source: Frontier Economics 

POLICY RECOMMENDATIONS 

We  have  identified  and  assessed  a  range  of  potential  options  to  address  the  barriers 
described above. The potential solutions identified drew on stakeholder input and ‘best 
practice’ identified when surveying country-based evidence. While we provide some high 
level  design  considerations  for  our  recommendations  in  the  main  body  of  the  report, 
further work will be needed on policy design and the assessment of different options.  

We find that, overall, our recommendations can be grouped into five categories: 

  Interventions  via  climate  and  renewable  policy,  and  support  for 
innovation:  this  group  of  solutions  is  designed  to  address  barriers  and  gaps 
related  to  the  relative  immaturity  of  sector  coupling  and  low-carbon  and 
renewable gas technologies; 

  A  regulatory  toolbox  to  address  cost  recovery  issues:  this  group  would 
serve to address barriers and gaps from group 2, i.e. issues contributing to an 
unlevel playing field across technologies; 

  A  number  of  changes  to  market  design  and  charging  arrangements  to 
make them more fit-for-purpose in the face of the expected changes in 
the  sector:  these  would  address  issues  stemming  both  from  the  relative 
immaturity  of  relevant  technologies,  and  the  historic  focus  on  natural  gas  in 
infrastructure regulation; 

  The provision of increased clarity on access to infrastructure would also 
aim to overcome barriers and gaps stemming from the historic focus on natural 
gas in infrastructure regulation; and 

Page 13 

 
 
 
  The 

co-ordinated 

facilitation  of 

infrastructure  planning  and 
decommissioning, which would be expected to help achieve a level playing field 
across  technologies,  avoid  the  risks  of  uncoupled  and  uncoordinated 
infrastructure  planning,  as  well  as  the  risks  related  to  interoperability  across 
markets and borders. 

This is  summarised  in  Figure  5  below.  We  then  present  proposed  solutions  in  further 
detail.  

Figure 5 Overview of barrier categories and solution categories 

Source: Frontier Economics 

Climate and renewable policy and support for innovation 

Support for innovation is key to addressing some of the barriers particularly relevant in 
the transition phase for renewable and low-carbon gas technologies.  

Indeed,  (financial)  support  for  Research  and  Development  (R&D),  pilots  or 
demonstration projects and, potentially, beyond that, ongoing support for further 
deployment following the demonstration phase4 would be a direct way to address 
positive externalities related to innovation. State aid rules and/or internal energy market 
legislation  would  need  to  ensure  that  any  ongoing  support  is  granted  in  a  way  that 
promotes competition and market integration.  

We  see  a  case  for  allowing  network  operator  ownership  (or  involvement  in) 
research-stage or pilot power-to-gas projects in specific circumstances to address 

4 R&D refers to fundamental research (typically led by academia) and the application of 
this  research  to  the  development  of  new  concepts  and  processes  (typically  led  by 
industry).  Demonstration  refers  to  the  testing  of  new  applications  in  a  commercial 
setting. At the research, development and demonstration phases, the focus is typically 
learning about the feasibility and costs of different approaches. During the deployment 
phase, the focus is on large-scale roll-out of a technology and achieving cost reductions 
as supply chains and expertise develop. R&D may continue during the deployment (and 
demonstration)  phases,  for  example  with  the  aim  of  helping  to  identify  incremental 
improvements to production processes and/or achieving cost reductions.  

Page 14 

Risk for interoperability across markets and bordersUncoupled and uncoordinated infrastructure planningFocus on natural gas in infrastructure regulationUnlevel playing field due to sector-and technology-specific tariffs and leviesRelative immaturity of relevant technologiesClimate / renewable policy and support for innovationFit for purpose market design and charging arrangementsRegulatory toolbox to address cost recovery issuesCo-ordinated infrastructure planning and decommissioningClarity on access to infrastructureBarriersSolutions/recommendations35421 
 
 
                                           
 
 
co-ordination  barriers.  Network  operator  involvement  would  need  to  be  targeted  in 
scope (e.g. limited to understanding technical impacts on the networks) and subject to 
conditions (such as time limits and knowledge sharing) to avoid potential longer-term 
negative  effects  on  competitive  and  market-based  investments.  NRAs  would  need  to 
play an important role in minimising potential negative consequences.  

Power-to-gas ownership by network operators could also be relevant once the 
transition phase has ended, in situations where it is difficult (or disproportionate) 
to  ensure  market  signals  convey  system  benefits  (e.g.  the  benefits  of  the  specific 
location of a facility) well enough. Again, NRAs would play an important role in ensuring 
that such projects would indeed be beneficial for the system and in verifying that it is 
not possible to secure market-based investment. 

Regulatory toolbox to address cost recovery issues 

As highlighted in the description of barriers above, the ways in which policy costs (such 
as RES support costs) and the costs of gas infrastructure are recovered matter for the 
uptake of renewable and low-carbon gases.  

A direct solution to the issue of power-to-gas facing end-user taxes on electricity would 
be to ensure that only final electricity consumption faces (cost-recovery) taxes 
and levies. 

Dealing  with  issues  related  to  sunk  and  decommisisoning  costs  requires  a  suite  of 
regulatory solutions. 

To reduce the risk of over-investment in gas infrastructure, leaving asset stranded 
risk with network operators may be an option. However, this may only have limited 
scope  of  application:  for  forward-looking  investments  over  which  network 
operators exercise a degree of discretion (and provided such investments can be 
easily  identified).  For  other  types  of  costs,  more  frequent  (regulatory)  reviews  of 
whether prospective investments are necessary may be beneficial. 

Regarding the distribution of the costs of legacy investment (and of decommissioning 
costs): 

  To minimise distortions between consumer choices between energy carriers, 
from 

infrastructure  costs  could  be  distributed  away 

sunk 
infrastructure users and towards taxpayers instead.  
If this is not feasible (or not acceptable), ensuring an equitable distribution 
of sunk costs between different energy carriers (i.e. electricity, gas and 
heat) could be an alternative to investigate.  

 

  Allowing  for  faster  recovery  of  costs  (e.g.  accelerated  regulatory 
depreciation) may also be part of the toolkit, although the benefit in terms of 
avoiding distortions to choices between energy carriers is less clear. 

Fit for purpose market design and charging arrangements 

Given the historical focus on natural gas, gas market design needs to evolve to efficiently 
accommodate renewable and low-carbon gases into the market. This is particularly the 
case given that much of the new capacity is expected to be connected at the distribution 
level.  

There  are  a  variety  of  connection  charging  approaches  that  avoid  the  first-
mover  disadvantage  while  still  preserving  locational  signals  (to  varying 
degrees). While there may be complexities in their implementation, such options have 
the potential to encourage the development of low-carbon and renewable gases while 
minimising  the  risk  of  incentivising  uptake  of  expensive  connections.  Consistency 

Page 15 

 
 
between  the  frameworks  for  connection  charging  and  for  dealing  with  connection 
requests (see “Clarity on access to infrastructure” below) would be important.  

The  creation  of  harmonised  injection  charging  rules  (at  distribution  level)  would 
increase certainty for developers regarding how they might be charged for use of the 
gas grid, in turn reducing the costs across the EU of deploying renewable and low-carbon 
gases.  

Successful integration of renewable and low-carbon gases into the market also requires 
that the framework for managing physical congestion is complete (in particular 
at distribution level). 

  Competitively  tendered  voluntary  agreements  between  network 
operators  and  participants  to  limit  injections  may  be  a  relatively 
straightforward measure to implement. 

  More  sophisticated  market-based  systems  allowing  for  real-time 
adjustment  of  bids  may  offer  greater  efficiency,  but  may  not  be  a 
proportionate solution if congestion issues remain limited. 

  Obliging participants to limit injections may be appropriate in situations 
where  there  may  be  a  limited  number  of  options  to  address  localised 
congestion issues, leading to possible market power concerns. 

Clarity on access to infrastructure 

Many of the barriers stemming from the historic focus of regulation on natural gas could 
be addressed through greater clarity on the access for new gases to infrastructure.  

To  reduce  the  risks  to  developers  stemming  from  uncertainty  regarding  quality 
standards, it would first be important to provide improved visibility on gas quality 
for gas producers. Clear rules on how quality is managed on an ongoing basis 
(such as the potential impacts on connection requests or on interruption of production 
and possible compensation) would help to further reduce risks.  

The  first  step  in  addressing  TSOs’  incentives  to  focus  on  gases  compatible  with  their 
infrastructure  would  be  a  review  of  regulatory  frameworks  to  identify  such 
biases.  An  additional  specific  (but  partial)  solution  might  be  an  obligation  for 
network  operators  to  connect  renewable  and  low-carbon  gas  sources  to  the  gas 
system, provided certain conditions (specified in advance, such as regarding gas quality) 
are met.   

Finally,  clarifying  whether  (and  under  what  conditions)  the  provisions  of  the 
Gas Directive apply to hydrogen (and other gases) is likely to provide increased 
clarity for developers regarding their ability to secure access to infrastructure, reducing 
the risks to investment. 

Co-ordinated infrastructure planning and decommissioning 

Improved co-ordination in planning and decommissioning decisions can help to 
improve the efficiency with which infrastructure is used. It could also help to improve 
interoperability across markets and sectors.  

An assessment of the implications of the expected change in the role of gas as 
well  as  the  mix  of  technologies  on  the  likely  optimal  level  of  gas  storage 
capacity would be a first step in addressing some of the uncertainty related to storage, 
and could provide a basis for assessing whether further intervention is needed.  

Co-ordinated  infrastructure  planning  (between  transmission  and  distribution 
level, and between electricity and gas networks) would allow operators to arrive 
at  a  shared  view  on  possible  developments  in  demand  and  supply  and  identify  and 

Page 16 

 
 
evaluate  investment  possibilities  in  different  parts  of  the  system.  This  would  be  an 
important enabler of lower costs. Regulatory incentives on individual operators to 
achieve cost savings at system level may provide the mechanism for ensuring any 
potential cost savings identified are actually achieved.  

Ensuring a more systematic consideration of the potential impacts on liquidity 
in  energy  system  planning,  in  particular  for  infrastructure  investment  and 
decommissioning decisions, would allow liquidity impacts to be traded off against other 
costs and benefits.5 This should therefore promote  ‘least cost’ infrastructure planning 
decisions in a wider sense. 

A framework for cross-border decommissioning decisions could provide a route 
to  avoiding  or  delaying  the  decommissioning  of  assets  that  might  deliver  benefits 
outside of the Member State in which they are located. By providing for more equitable 
sharing  of  decommissioning  costs  across  borders,  it  may  also  help  to  reduce  issues 
related to dismantling costs weighing on gas grid fees. 

Overview 

Figure 6 to Figure 10 provide an overview of how the recommendations set out above 
address  individual  short-listed  barriers.  Solutions  are  mapped  to  the  categories 
described above through colour-coding, with the corresponding groups identified in the 
top right corner of each figure.  

Figure 6 Recommendations to deal with the relative immaturity of relevant technologies 

Source: Frontier Economics 

5 For example, conversion of an existing pipeline to use hydrogen may bring benefits in 
terms of decarbonisation, but there may be a risk that it contributes to a fragmenting 
of the gas market. 

Page 17 

 
 
 
 
                                           
 
 
Figure 7 Recommendations to deal with the unlevel playing field due to sector-/technology-
specific tariffs and levies 

Source: Frontier Economics 

Figure 8 Recommendations to deal with the focus on natural gas in infrastructure regulation 

Source: Frontier Economics 

Page 18 

 
 
 
 
 
 
Figure 9 Recommendations to deal with uncoupled / uncoordinated infrastructure planning 

Source: Frontier Economics 

Figure 10 Recommendations to deal with the risk for interoperability across markets and 
borders 

Source: Frontier Economics 

Page 19 

 
 
 
 
 
 
 
2  ACRONYMS  

AE[R] 

CBA 
CEER 
CAPEX 
CCS 
CCU 
CHP 
CMP 
DAC 
DSM/DSR 
DSO 
E[R] 

EC 
EU 
ENTSO-E 

ENTSOG 

(EU) ETS 
GHG 
GoO 
IEA 
IRENA 
LNG 
NRA 
OECD 

OECD Europe 

OPEX 
PtG 
PCI 
PV 
R&D 
RED 
RED II 

SoS 
TSO 
TYNDP 

[R]evolution 

scenario  developed  by 

Advanced  Energy  [R]evolution  scenario  developed 
by Greenpeace 
Cost-benefit analysis 
Council of European Energy Regulators 
Capital Expenditure 
Carbon Capture and Storage 
Carbon Capture and Use 
Combined Heat and Power 
Congestion Management Procedure 
Direct Air Capture 
Demand-side management/response 
Distribution System Operator 
Energy 
Greenpeace  
European Commission 
European Union 
European  Network  of  Transmission  System 
Operators for Electricity 
European  Network  of  Transmission  System 
Operators for Gas 
(European Union) Emissions Trading System 
Greenhouse gases 
Guarantee of Origin 
International Energy Agency 
International Renewable Energy Agency 
Liquified natural gas 
National Regulatory Authority 
Organisation 
Development 
all  European  members  of  the  OECD:  Austria, 
Belgium, Czech Republic, Denmark, Estonia, Finland, 
Iceland, 
France,  Germany,  Greece,  Hungary, 
Ireland, 
the  Netherlands, 
Italy,  Luxembourg, 
Norway, Poland, Portugal, Slovak Republic, Slovenia, 
Spain,  Sweden,  Switzerland,  Turkey  and  United 
Kingdom. 
Operational Expenditures 
Power-to-Gas 
Project of Common Interest 
Photovoltaic 
Research and development 
Renewable Energy Directive (2009/28/EC) 
Renewable 
(2018/2001/EC) 
Security of Supply 
Transmission System Operator 
Ten-year Network Development Plan 

for  Economic  Co-operation  and 

Directive 

(recast) 

Energy 

Page 20 

 
 
 
 
 
3  INTRODUCTION 

In this chapter we state the objectives of the study, including definitions and scope for 
the technologies analysed, we set out the structure of the report and we summarise the 
key findings of  our analysis on the outlook for  the  EU  energy system  and the  role of 
gases within it.  

3.1  OBJECTIVE 

This final report presents the results of the project. The main objectives have been as 
follows: 

Objective 1 – The initial analysis provides the context by describing a possible future EU 
energy system, the role of gases within the system, and relevant sector-coupling and 
renewable and low-carbon gas technologies. 

Objective 2 – The core part of this study deals with identified regulatory barriers and 
gaps in Member States as well as inconsistencies across Member States. 

Objective  3  –  Based  on  the  barriers  and  gaps  identified  under  Objective  2,  policy 
recommendations are provided.   

Figure 11 

Summary of analytical steps required  

Source: Frontier Economics, CE Delft  

3.2  STRUCTURE OF THIS REPORT 

This study is structured as follows: 

  Section 3.3 gives an overview of the insights from the analysis under Objective 1, 
the initial analysis, while section 3.4 clarifies technical definitions and the scope. 

  Chapter 4 sets out the methodology followed to: 

- 
- 

identify regulatory barriers and gaps (4.1); and 
identify and assess solutions for barriers and gaps (4.2). 

  Chapter 5 presents:   

- 
- 

the list of barriers and gaps, allocated to a long and a short list; and 
the solutions for each short-listed barrier and gap. 

  Chapter 6 summarises the policy recommendations. 

Page 21 

 
 
 
  Appendix A provides more detail on the approach to barrier identification. 
  Appendix  B  gives  an  overview  of  the  major  findings  of  the  country-based 

research. 

  Appendix C includes the detailed assessment of solutions envisaged to overcome 

regulatory barriers and gaps. 

3.3  OVERVIEW OF THE FUTURE ENERGY SYSTEM AND THE ROLE OF GAS  

This  section  summarises  the  key  findings  of  our  analysis  on  the  outlook  for  the  EU 
energy  system  and  the  role  of  gases  within  it.  The  underlying  detail  is  set  out  in  a 
separate report (the ‘Intermediate Report’). 

This section is structured as follows: 

  We first describe the outlook for the future EU energy system. 
  We describe the role of gases within this, and the implications for infrastructure. 
  We outline how linkages between energy carriers could evolve.  
  Finally,  we  set  out  the  high-level  policy  implications  of  the  findings  of  the 
Intermediate Report. These have guided our thinking on regulatory barriers and 
gaps to renewable gases and sector coupling technologies.   

3.3.1  THE FUTURE EU ENERGY SYSTEM 

In the coming decades, the EU energy system needs to change dramatically to make 
the transition to a decarbonised energy system. This transition is necessary to achieve 
the  EU’s  2030  climate  targets  as  well  as  the  EU’s  commitments  under  the  Paris 
Agreement, which aims to limit the average global temperature rise to well below 2°C. 
An  assessment  of  recent  literature  leads  to  the  conclusion  that  despite  significant 
uncertainties, a number of likely key elements of the EU’s future decarbonised energy 
system to 2050 can be identified. 

The first is that total final energy demand is  expected to reduce significantly through 
energy efficiency measures in all end-use sectors. Key drivers include a large reduction 
in  heat  demand,  but  also  an  increase  in  energy  efficiency  in  industry  and  transport 
(including a shift from more to less energy-intensive modes of transport, such as public 
transport). This is illustrated in Figure 12. 

Page 22 

 
 
 
Figure  12  EU  final  energy  demand:  historic  data,  forecast  for  2030  and  average  for  the 
decarbonisation scenarios for 2050 developed for the Commission’s ‘Long Term Strategy’ 

Source:  European  Commission  (2018)  “A  Clean  Planet  for  all,  A  European  strategic  long-term  vision  for  a 
prosperous, modern, competitive and climate neutral economy”, COM(2018) 773 final. 

While overall final energy demand is expected to decrease, final demand for electricity 
will increase, due to increased electrification of heating and transport. This is 
illustrated by the Commission’s Long-Term Strategy6, which sees electricity demand 
rise in all analysed pathways in Figure 13. 

6 European Commission (2018) “A Clean Planet for all, A European strategic long-term 
vision for a prosperous, modern, competitive and climate neutral economy”, COM(2018) 
773 final. 

Page 23 

0200400600800100012001400198019902000201020202030204020502060Mtoe 
 
 
                                           
 
 
Figure 13 EU final electricity consumption (historical and projected) 

Source:  European  Commission  (2018)  “A  Clean  Planet  for  all,  A  European  strategic  long-term  vision  for  a 
prosperous, modern, competitive and climate neutral economy”, COM(2018) 773 final. 

Demand for electricity will be further increased by demand for Power-to-X production 
(amplified by the conversion efficiency losses involved with Power-to-X production).  

In  power  production,  the  most  carbon  intensive  fossil  fuels  (coal,  lignite,  oil)  are 
expected to be phased out, with use of natural gas potentially increasing in the transition 
(i.e.  to  2030)  but  eventually  largely  being  phased  out  by  2050.  Renewable  power 
production is generally expected to increase (as illustrated in Figure 14).  

Figure 14 Projected share of RES-E in 2050 in EU / OECD Europe 

Sources: ASSET, 2018, “Sectoral integration: long-term perspective in the EU Energy System, final report”. 
Greenpeace, 2015, “Energy [r]evolution: A sustainable world energy outlook 2015, 100% renewable energy 
for all”. IRENA, 2018, “Global energy Tranformation: a Roadmap to 2050”. 

Note:  IRENA  (2018)  figures  relate  to  the  2050  REmap  scenario.  Greenpeace  (2015)  figures  relate  to  the 
‘Energy  Revolution’  (E[R])  and  ‘Advanced  Energy  Revolution’  (AE[R])  scenarios  and  cover  OECD  Europe 
(including Israel and Switzerland).  

The  growth  in  renewables  (much  of  which  will  be  from  intermittent  sources,  such  as 
solar  PV  and  wind)  means  that  additional  flexibility  will  be  required  on  the  electricity 
system. The long-term role of nuclear power is a key uncertainty, as is the deployment 
of fossil fuel generation with CCS (cf. definition in chapter 3.4).  

Page 24 

 
 
 
 
Hence, the flexibility requirement of the electricity grid is expected to be achieved by a 
combination  of  demand  side  management/response  (DSM/DSR),  energy  storage  (for 
example in batteries, heat storage, or in hydrogen, synthetic methane or other chemical 
energy carriers) and peak gas power plants. The latter can be run on natural gas, with 
increasing shares over time of renewable or low-carbon gases (biomethane, hydrogen 
and/or methane from renewable electricity or from natural gas with CCS). 

3.3.2  THE  ROLE  OF  GASES  AND  SECTOR  COUPLING  AND  IMPLICATIONS  FOR 

INFRASTRUCTURE 

It  is,  in  principle,  possible  to  use  all  the  different  renewable  and  low-carbon  gases 
(including hydrogen) in all applications for which natural gas is used today (such as heat 
and power production), as well as others for which natural gas is not significantly used 
at the moment (such as transport). This would, however, require the gases to meet the 
current  quality  standards,  or  alternatively,  an  adaptation  of  the  quality  standards 
themselves and/or end-use equipment and infrastructure. Overall, the continued use  of 
gases could help to reduce the costs of decarbonisation through a combination of limiting 
the costs of changing end-user appliances and avoiding the need for reinforcements and 
upgrades  to  the  electricity  grid  (by  making  use  of  the  existing  gas  grid  to  transmit 
energy).  

However, the respective roles of different types of gases in the future energy mix are 
still  uncertain.  Natural  gas  might  play  a  minor  enduring  role  in  industry  and  power 
generation.  The  extent  of  this  role  may  be  partly  dependent  on  whether  CCS  can  be 
deployed commercially, which is itself uncertain. Many scenarios also feature significant 
use  of  renewable  and  low-carbon  gases.  Precisely  which  gases  are  used  is  a  further 
uncertainty, with hydrogen, synthetic methane and biomethane all featuring in varying 
quantities in the different studies by 2050. 

This uncertainty is illustrated in Figure 15 below.  

Figure 15 EU demand for gaseous fuels, in 2015, forecast for 2030, baseline for 2050 and different 
decarbonisation scenarios for 2050 developed for the EU 2050 strategy 

Source:  European  Commission  (2018)  “A  Clean  Planet  for  all,  A  European  strategic  long-term  vision  for  a 
prosperous, modern, competitive and climate neutral economy”, COM(2018) 773 final. 

Page 25 

050100150200250300350400MtoeNatural gasBiogas and waste gasSynthetic methaneHydrogen 
 
 
Clearly, developments in cost will be an important driver of the extent to which gases 
are used in the future and, if so, which gases are predominantly used. But policy will 
also  play  a  role.  In  particular,  given  the  co-ordination  that  would  be  required  (e.g. 
appliance  switchovers,  infrastructure  upgrades),  any  future  in  which  hydrogen  is 
transported  or  used  in  significant  quantities  within  the  EU  requires  strategic 
decisionmaking by policymakers (whether at national or at EU-level).  

These developments have a range of possible impacts on gas infrastructure and storage 
needs.  These  impacts  differ  significantly  between  scenarios  presented  in  recent 
literature, but include the following: 

  Since natural gas demand is expected to decrease in the coming decades, the 
(average)  utilization  level  of  the  transmission  grid,  LNG  import  terminals  and 
import pipelines is also likely to decline, mitigated by the extent to which these 
convert to using increasing shares of renewable or low-carbon gases.  

  The impacts on the transmission grid, the distribution grid and storage facilities 
are likely to differ from location to location. Some existing grids might be used 
for renewable methane or biomethane, or transformed to (local) hydrogen grids, 
and others may become obsolete.  

  Any  large-scale  use  of  hydrogen  might  also  require  conversion  of  existing  gas 
storage or new hydrogen storage locations. New fuelling infrastructure may need 
to be developed for the transport sector. 

  Existing gas storage facilities might need to be adjusted to allow the storage of 

renewable gases. 

  Synthetic  methane  production  is  likely  to  require  dedicated  CO2  transport 
industrial  processes  to 
from  air 

infrastructure  to  transport  CO2  captured 
methanation  plants,  or 
technologies.  

further  development  of  CO2-capture 

from 

  Given that much of renewable and low-carbon gas production is expected to be 
located at distribution level, flows on the distribution grid (and flows between the 
distribution and transmission level) will require increased active management.  
  Greater substitutability of gas and power for final energy consumption (e.g. in 
heating) is likely to require closer co-ordination between gas and power system 
operation, both at transmission and distribution level. 

3.3.3  LINKAGES BETWEEN ENERGY CARRIERS 

As well as increased gas and electricity sector coupling, large-scale deployment of the 
technologies that are part of the hydrogen and methane supply chains will also result in 
linkages between natural gas, hydrogen and methane. This is illustrated in Figure 16. 

Page 26 

 
 
 
Figure 16 
gas, hydrogen and methane  

High-level overview of linkages between gases for energy use in 2050: Natural 

  Natural  gas  reforming  and  CCS  provide  the  possibility  to  convert  natural  gas 

upstream in the supply chain to low-carbon hydrogen. 

  Hydrogen  production  from  biomass  competes  with  biomethane  production  from 
biomass. The CO2 produced in both processes can be captured and stored; it could 
also be used to produce synthetic methane.  

  Similarly, hydrogen could either be used directly or in synthetic methane production. 
This could lead to competition between synthetic methane and hydrogen, with the 
cost of the CO2 used in the synthetic methane process (see point above) becoming 
an important factor in determining the effectiveness of this competition.  

  As  discussed  earlier,  hydrogen  could  be  injected  into  the  methane  (natural  gas) 
pipeline  network  up  to  a  blending  level  of  2-20%  by  volume  (with  the  maximum 
blending level still uncertain) without needing substantial additional investments in 
the gas network.  

  Parts of the natural gas network could be adapted to transport 100% hydrogen. This 
also likely requires the  replacement  of  end-use appliances and turbines. Although 
such adaptation could lead to a situation in which natural gas networks and hydrogen 
networks  exist  in  parallel,  it  could  provide  the  best  match  with  local/regional 
production capacities in certain areas. Hydrogen and methane could be produced, 
transported and consumed more locally than is the case for natural gas today.  In 
such a scenario, links between the hydrogen and methane supply chains would be 
broken  at  the  level  of  injection  to  the  grid  (as  they  would  no  longer  be  blended 
together).  However,  links  would  remain  elsewhere  in  the  value  chain  (e.g.  in 
production), as set out in the second and third bullets above.   

Page 27 

HydrogenfrombiomassMethanepipeline networkMethanevehiclesMethanepower plantMethaneboilerSyntheticmethaneproductionBiomethaneproductionWater electrolysisHydrogenpipeline networkHydrogenvehiclesHydrogenboilerHydrogenpower plantNatural gas reforming= CO2= H2= methane= ‘hythane’= competingforlocationsOtherCO2-sourcesCO2storageMethanestorageHydrogenstorage 
 
 
  Hydrogen,  methane  and  CO2  could  all  be  stored  in  underground  locations  or  in 
available gas storage vessels. These are further discussed in the relevant sections 
of the Appendices to the Intermediate Report. Some of the underground locations 
may be suitable for storing either gas, but this is still a topic of research. Also, natural 
gas  (LNG)  transport  vessels  could  perhaps  be  modified  to  transport  hydrogen  or 
CO2. In such cases these gases would be competing for the same storage capacity.  

In short, the simultaneous development of low-carbon and renewable hydrogen and 
methane supply chains would create several supply chain linkages, some of which are 
complementary and synergetic, and some of which are substitutional. Further linkages 
might be developed in the future if other chemical energy carriers (such as ammonia) 
are deployed in significant quantities. 

3.3.4  IMPLICATIONS FOR POLICY 

The findings from our literature review have a range of implications on gas infrastructure 
and  storage  needs  and  policy.  While  the  precise  impacts  differ  significantly  between 
scenarios applied in recent literature, five themes emerge.  

The first is the importance of continued innovation and learning in technologies that are 
currently less mature. Any large-scale market uptake of renewable and low-carbon gas 
technologies will require innovations and R&D efforts in all aspects of the value chains, 
to further develop the necessary technologies,  to create and preserve options for the 
future,  and  to  reduce  cost  and  improve  efficiencies.  This  is  expected  to  require  
significant  investments  over  the  coming  decades,  for  example  in  renewable  energy 
production,  production  plants  for  the  gases,  upgrading  of  existing  infrastructure  and 
storage, new infrastructure and storage, and new end-use applications.  

The  second  is  the  variety  of  technological  approaches  to  renewable  and  low-carbon 
gases and sector coupling technologies. This highlights the importance of a level playing 
field for gases (compared to other energy carriers) and between different gases. In the 
transition  phase  there  may  need  to  be  an  element  of  support  prioritising  those 
technologies that are potentially more promising. However, as support is phased out, it 
is important that the market can send efficient signals regarding technology choices to 
ensure  that  the  energy  transition  can  happen  at  least  cost  to  society.  It  will  also  be 
important to maintain a sufficient degree of technology openness to facilitate the market 
entry of energy carriers that might grow in relevance over time (e.g. ammonia).  

The third is that, while the use of natural gas is expected to be largely phased out by 
2050,  new  gases  will  begin  to  flow  in  increasing  quantities  in  existing  infrastructure. 
Some infrastructure may be switched over entirely to new gases (such as hydrogen). 
New  infrastructure  may  also  be  focussed  on  new  gases.  As  a  result,  the  focus  of 
infrastructure regulation will need to shift from natural gas to a variety of different (low-
carbon and renewable) gases.   

The fourth is that interlikages and substitutability between the electricity, gas and heat 
sectors  in  all  areas  of  the  value  chain  are  likely  to  grow  going  forward.  As  a  result, 
planning  the  required  investments  efficiently  will  likely  require  an  integrated 
development of the gas and electricity systems. Given much of the new gas production 
may  be  located  at  distribution  level,  co-ordination  in  system  planning  and  operation 
between transmission and distribution levels is also likely to be important.  

The  fifth  is  that  different  countries  or  regions  may  adopt  different  technological 
approaches.  This  suggests  that  attention  needs  to  be  paid  on  how  to  ensure  that 
different gases can co-exist both within and between countries and regions.  

These themes have influenced how we have framed the analysis of potential regulatory 
barriers and gaps. We consider each of these areas in turn in the chapters that follow.  

Page 28 

 
 
3.4  DEFINITIONS AND SCOPE 

This  study  mentions  a  wide  range  of  gases  that  are  likely  to  play  a  role  in  the 
decarbonisation  of  the  EU  energy  supply  of  the  coming  decades.  To  prevent 
misunderstandings  and  ensure  a  uniform  terminology  throughout  this  project,  a 
comprehensive  list  of  relevant  definitions  has  been  developed.  This  adheres  to  the 
definitions included in Article 2 of the Renewable Energy Directive recast (RED II) , with 
additional terminology specific to this report defined only where necessary.  

A selection of key definitions from the RED II and additional definitions that are relevant 
for this study are provided in the following table.  

Term 
Selected definitions from RED II 

Meaning 

Biofuels 
Biogas 
Additional terminology relevant for this study 
Gases 

Energy from renewable 
sources 
Or 
Renewable energy 

Renewable liquid and 
gaseous transport fuels 
of non-biological origin 

Renewable gases/ 
Gases from renewable 
sources 

Natural gas 

Biomethane 

Power-to-Gas, PtG 

Renewable hydrogen 
Hydrogen from fossil 
sources  
Hydrogen from fossil 
sources using Carbon 
Capture and Storage 

Synthetic methane 

Energy from renewable non-fossil sources, namely wind, 
solar  (solar  thermal  and  solar  photovoltaic)  and 
geothermal  energy,  ambient  energy,  tide,  wave  and 
other  ocean  energy,  hydropower,  biomass,  landfill  gas, 
sewage treatment plant gas, and biogas 
Liquid  or  gaseous  fuels  which  are  used  in  the  transport 
sector other than biofuels or biogas, the energy content 
of  which  is  derived  from  renewable  sources  other  than 
biomass. 
Liquid fuel for transport produced from biomass 
Gaseous fuels produced from biomass 

All  types  of  gaseous  fuels,  including  natural  gas, 
hydrogen,  renewable  gas,  biomethane,  decarbonised 
gas, etc. 
Gaseous  fuels  produced  from  renewable  non-fossil 
sources,  namely  wind,  solar  (solar  thermal  and  solar 
photovoltaic)  and  geothermal  energy,  ambient  energy, 
tide,  wave  and  other  ocean  energy,  hydropower, 
biomass,  landfill  gas,  sewage  treatment  plant  gas  and 
biogas 
Naturally  occurring  gas  of  fossil  origin,  consisting 
primarily of methane   
Gaseous fuels with a quality that allows injection into the 
natural  gas  grid  produced  either  from  biogas  through 
upgrading, or by thermal gasification of biomass. 
Technology to transform electricity into a gaseous energy 
carrier (notably hydrogen or methane) 
Hydrogen produced from renewable energy sources 
Hydrogen  derived  from  either  gasification  of  solid  fuels 
(e.g. coal) or from reforming of natural gas.  
Hydrogen  derived  from  either  gasification  of  solid  fuels 
(e.g.  coal)  or  from  reforming  of  natural  gas.  In  this 
report,  we  use  the  term  to  primarily  refer  to  hydrogen 
produced from natural gas where the CO2 has been to a 
high  extent  captured  (sometimes  referred  to  as  blue 
hydrogen) 
Methane produced from hydrogen.  

Page 29 

 
 
  
A schematic overview of the main categories of gases covered in this study is depicted 
in the figure below. We note that these different gases may be transported in separate 
infrastructures or blended in a single infrastructure. 

Figure 17 

An overview of the gases included in this report: illustrative definitions  

Source: Frontier Economics, CE Delft  

Page 30 

Anaerobic digestionThermal gasificationElectrolysis with RESBiogasBiomethaneRenewable HydrogenHydrogen from fossil sourcesNatural GasGas upgradingMethanisation via bio / air captureNatural gas with CCS or CCUExplorationProcessGas product(Synthetic) MethaneMethanisation via (remaining) industry/fossil power generation emissions? 
 
 
 
 
 
 
 
4  METHODOLOGY  FOR  IDENTIFYING  REGULATORY  BARRIERS  AND 

SOLUTIONS 

This chapter describes the methodology followed to complete Objectives 2 and 3 of the 
assignment, and is structured as follows: 

  We first explain our methodology for identifing regulatory barriers and gaps. 
  We  then  explain  our  methodology  for  identifying  and  assessing  possible 

solutions, and for translating this assessment into recommendations.  

It is important to note that, due to the timings of the study, neither the identification of 
barriers nor the assessment of solutions takes full account of recently EU energy market 
legislation that has recently come into effect, originally forming part of the Commission’s 
Clean energy for all Europeans package of proposals.7 

4.1  METHODOLOGY OF REGULATORY BARRIERS AND GAPS ANALYSIS 

This section is structured as follows: 

  We first explain how we define the concept of a ‘regulatory barrier or gap’. 
  We then set out our methodology for identifying potential regulatory barriers and 
gaps to sector coupling technologies and renewable and low-carbon gases.   

4.1.1  DEFINITION OF BARRIERS  

As  illustrated  in  Figure  18,  for  the  purposes  of  this  study,  regulation  is  defined  as 
encompassing the legal framework at the EU or Member State level, acts of regulatory 
bodies  and  agencies  as  well  as  administrative  practice.  Regulation  (or  the  absence 
thereof) is found to possibly risk constituting a barrier to sector coupling and renewable 
and  low-carbon  gas  technologies  if  it  threatens  either  a  level  playing  field  between 
technologies or the development of innovative technologies. 

Such a threat to the level playing field may be rooted in distortions in relation to: 

 
 

the most efficient use of existing infrastructure (pipelines, storages, etc.) 
the  most  efficient  new  investment  into  traditional  technologies  (pipelines, 
storages,  etc.)  or  new  technologies  (e.g.  power-to-gas  facilities,  carbon 
capture and storage technologies, etc.). 

As a result, the identified barriers may both threaten the achievement of climate policy 
targets and/or contribute to inefficiently high costs of the energy transition.  

https://ec.europa.eu/energy/en/topics/energy-strategy-and-energy-union/clean-

7 
energy-all-europeans  

Page 31 

 
 
 
 
                                           
 
 
Figure 18 

Definition of barriers and gaps  

Source: Frontier Economics 

It is important to note the following: 

  Barriers and gaps: Based on the retained definition, the absence of regulation 

may also constitute a barrier. This study therefore also covers regulatory gaps.      

  Scope  of  barriers  for  sector-coupling  and  related  technologies:  While 
barriers to electrification may be viewed as a barrier to sector coupling between 
the electricity and gas sectors, the scope of this study does not include barriers 
to electrification. 

4.1.2  METHODOLOGICAL APPROACH FOR IDENTIFYING BARRIERS 

To  identify  regulatory  barriers  and  gaps  the  following  methodological  steps  were 
implemented, as described in Figure 19: 

  A conceptual benchmark for regulation was developed to capture the scope 
of regulation(s) assessed as part of the study, in line with the definition provided 
in section 4.1.1; 

  Research  was  carried  out  to  collect  qualitative  evidence  and  feedback  on 
barriers encountered by pilot projects in a selection of countries (country-based 
research);  

  Submissions from stakeholders were invited and reviewed; 

  A long list of barriers was established based on the above; and 

  Within this list, a short list of barriers was agreed that would then be assessed 

with a view to provide recommendations (see section 5). 

Each step is described further below.  

Page 32 

Regulation …Legal frameworkon EU or MS levelActsof regulatory bodies and agenciesAdministrative Practice… is a barrier if it threatens …either a level playing field between technologies to ensure cost-efficient deploymentor the development of (promising?) innovative technologies… which finally leads toa threat to achieving the climate policy targets (effectiveness) orextra costs of the energy transition (efficiency)The absence of a regulation may also pose a barrier. We also cover gaps.As well as adjusting to facilitate the uptake of sector coupling technologies [transition issues]… Natural GasCrude OilRenewableNuclearCoalNatural GasCrude OilRenewableNuclearCoal…regulation may also need to adapt in other ways once they are adopted [steady state issues] 
 
 
 
 
Figure 19 

Overview of methodology for the identification of regulatory barriers and gaps 

Source: Frontier Economics 

The  conceptual  benchmark  for  regulation  (see  Figure  20)  was  used  to  map  the 
regulations to be assessed with a view to identifying barriers and gaps. The benchmark 
included a detailed list of the regulatory areas under analysis, as well as an an initial 
view on the regulatory arrangements that might be considered efficient in each area. 
The benchmark effectively provided a detailed structure for the analysis, in particular 
for the country-based research (see below).  

The  benchmark  also  highlighted  that  barriers  could  stem  from  within  each  type  of 
regulation,  from  national  differences  in  those  regulations,  from  differences  in  the 
treatment of energy carriers, or from differences in regulation at TSO- and DSO-level.  

Page 33 

 
 
 
 
Figure 20 
the whole system   

The  conceptual  benchmark  for  regulation  illustrates  the  coverage  of  barriers in 

Source: Frontier Economics 

The  conceptual  benchmark  captures  the  essential  consideration  that  in  an  efficient 
situation the operator (of existing facilities) or investor of (new) infrastructure will need 
to tap into all potentially available sources of revenue: 

  Commercial revenues that may be for instance achieved through some merchant 

operation, e.g. by contracting a facility to an energy trader; 

  Regulated  revenues  –  these  may  relate  to  capped  revenues  of  monopoly 
infrastructure, revenues that reward certain wider system benefits of a facility or 
additional revenues that reward the environmental/climate benefit of a facility. 

System benefits could for instance relate to avoiding the need to invest in alternative 
infrastructure. For instance, a power-to-gas facility may help avoid investment in power 
grids, if renewable electricity can be converted to gas and the energy then transported 
in an existing pipeline system, instead of reinforcing the electricity grid to transport the 
additional  power.  This  also  implies  that  some  of  the  system  benefits  will  inevitably 
depend on the precise location where a facility is situated within a given electricity and 
gas network topology. 

The  regulatory  environment  needs  to  be  able  to  facilitate  the  monetisation  of  all 
systemic (and climate) benefits of a facility by the operator or owner (i.e. the financial 
rewards ultimately need to be bundled in the hands of the operator/investor). In some 
cases,  this  may  only  be  achieved  by  generating  multiple  revenue  streams,  which 
ultimately  benefit  the  operator  or  investor.  It  will  not  necessarily  require  that  the 
operator/investor is the direct beneficiary of the primary revenue streams.8  

8 For example, the owner of a power-to-gas facility may benefit from merchant revenues 
of arbitrage trades between gas and power, if the actual trades are carried out by an 
energy trader, but the traders book (and pay to the benefit of the operator/investor) 
capacity in the power-to-gas facility. 

Page 34 

Technical regulations (gas)Business casesNational differencesDifferences power vs gasDifferences TSO vs DSO SoS regulation and flexibilityEnergy marketsRegulationInternalisation of GHG emissions Decarbonisation targetsIdentification of gas types for support/exemption Guarantees of origin & rules on x-border trade thereofInternalisation of SoS benefitsCross-sectoral SoSRisk preparednessValue of flexibilityRegulation of methane/natural gas, biomethane, hydrogenConversion of use (H2, CO2)InteroperabilityGas qualityTariff regulation3rd party accessUnbundling+ curtailmentCommercial revenuesRegulated revenuesSmart Technology: Digitalisation/smart gridsCross sectoral policy guidancePossible distortions to a level playing fieldEconomic regulation of infrastructureGovernance of renewable and climate policy 
 
 
 
 
 
 
                                           
 
 
If  this  is  not  achieved,  there  can  be  a  barrier  or  a  gap  that  will  keep  operators  or 
investors  from  deploying  the  facility  that is  most  beneficial  from  an  overall  economic 
perspective. 

Based  on  this  benchmark,  a  number  of  potential  barriers  and  gaps  were  identified, 
drawing on three main types of input:  

  Expert insights: the energy transition and the consequential need for regulatory 
adjustment are currently much discussed topics. We used the experience of our 
project work, clients and insights from conferences for the establishment of the 
long list. 

  Expert group meeting on 21st November 2018 in Brussels: In our meeting with 
the  expert  group9,  we  gained  insights  from  the  experience  of  relevant 
stakeholders that contributed further to the list of barriers and gaps. 

  Stakeholder  workshop  in  Brussels  on  6th  of  March  2019:  We  received  further 
comments from a larger group of stakeholders during and after the presentation 
of our intermediate findings at a workshop held on March 6th 2019. 

More detailed information on the research methodology can be found in Appendix A.  

Country-based research into representative Member States enabled us to compare 
the conceptual benchmark against current practice in those Member States. 

Thirteen Member States (Belgium, Bulgaria, Denmark, France, Germany, Greece, Italy, 
Lithuania,  Poland,  Slovakia,  Spain,  The  Netherlands  and  the  United  Kingdom  (UK)), 
were  the  subject  of  research.  The  selection  of  Member  States  was  agreed  with  the 
Commission and designed to cover a wide and representative range of Member States 
and to ensure a  range  of possible low-carbon  gas and/or  sector coupling applications 
are covered. More information on the country selection and the key barriers per country 
can be found in Appendix A.  

The conceptual benchmark for regulation fed directly into the approach for conducting 
the  country-based  research.  Figure  48  in  Appendix  B  gives  an  overview  of  the 
information collected as part of this exercise. It is important to note that the country-
based  research was based  on a desktop  review of  regulations and on interviews with 
country stakeholders. The stakeholders included a mix of energy producers, vendors, 
network operators or industry players, in particular those involved in pilot projects for 
sector  coupling  and  low-carbon  and  renewable  gases  technologies.  We  note  that  the 
research  methodology  was  targetted  at  gaining  insights,  in  particular  feedback  from 
local developments, and was not designed as a systematic survey. Due to the different 
interview partners, but also due to the differences in status and national plans in relation 
to  the  energy  transition  across  the  countries,  the  findings  are  not  all-encompassing. 
While the research for each country focuses on the current barriers and gaps faced in 
their  current  situation,  and  in  some  cases  anticipated  in  the  future,  it  does  not 
necessarily  mean  that  these  are  the  exhaustive  list  of  barriers  that  may  arise  in  this 
country in the future (absent intervention). Where this helps understand the nature of 
barriers,  references  to  country-specific  examples  are  included  in  section  5;  by 
construction those examples are not exhaustive. 

Stakeholders (including EU sector associations,  Member States and  NRAs)  added to 
the  country-based  analysis  of  barriers  by  providing  their  assessments  of  the  most 
pressing barriers. A workshop was held on March 6th 2019 and provided the opportunity 
for stakeholders to participate to the discussion. A presentation of the barriers and gaps 

9  Participating  parties  were  ACER,  CEER,  CEDEC,  European  Biogas  Association,  ECF, 
ENTSO-E, ENTSOG, Eurogas, Eurelectric, E3G, GEODE, Hydrogen Europe 

Page 35 

 
 
 
                                           
 
 
identified at that point in the study was shared with participants ahead of the workshop. 
The stakeholders had the chance to share additional comments with the consortium in 
form of  a written response. Input from stakeholders was used to substantiate and/or 
ensure  the  completeness  of  the  list  of  barriers  identified.  We  also  note  that  several 
stakeholders  opted  to  provide  views  on  solutions  to  address  barriers  and  gaps.  The 
consortium used this input in the subsequent step of the study.  

The  Long  List  of  barriers  brings  together  the  information  from  the  conceptual 
framework, the country-level analysis and the stakeholder perspectives. The Long List 
includes  some  Member  State  specific  barriers  as  well  as  barriers  stemming  from 
inconsistencies across regulatory regimes in different Member States. The explanation 
of the barriers on the long list focuses on setting out clearly why and how each factor 
might act as a barrier or gap - i.e. explain which market or regulatory failure is occurring 
and the impact on the level playing field in terms of development of renewable and low-
carbon gases and sector coupling technologies. 

The  Short  List corresponds  to  those  areas  for  which  a  set  of  recommendations  has 
been elaborated in further stages of the study, as agreed by the Commission and the 
consortium.  

4.2  METHODOLOGY TO IDENTIFY AND ASSESS SOLUTIONS 

In this sub-section, we: 

  Explain how we have identified potential solutions for short list barriers; 
  Set out our criteria for qualitatively assessing potential solutions; and 
  Set out how we translate the qualitative assessment of potential solutions into a 

recommendation. 

4.2.1  IDENTIFICATION OF SOLUTIONS 

In  identifying  potential  solutions  for  assessment,  we  have  drawn  on  the  following 
sources: 

  Country-based research: In some cases, individual countries have taken, or 

are considering taking, action to address some of the barriers identified. 

  Stakeholder  feedback:  Stakeholders  have  suggested  a  number  of  potential 
policy options to promote sector coupling technologies. We have included those 
potential solutions that are linked to the short-listed barriers. 

  Own  analysis:  We  have  considered  (from  first  principles)  potential  solutions 
that  could  directly  address  some  of  the  barriers  raised,  also  drawing  on  work 
carried out to develop the ‘conceptual benchmark for regulation’. 

4.2.2  ASSESSMENT CRITERIA 

We use the following criteria to qualitatively assess potential solutions: 

1.  Net societal costs and benefits: What is the expected balance of overall costs 

and benefits to (EU) society as a whole? 

a.  In  assessing  this  criterion,  we  make  the  simplifying  assumption  that 
delivery  against  EU  environmental  objectives  is  held  constant.  In  other 
words,  we  assume  that  individual  policy  options  do  not  affect  whether 
binding EU renewable energy and climate targets are met, but only affect 
how  targets  are  met.  As  a  result,  different  solutions  might  still  have 
different  effects  on  the  costs  of  achieving  targets.  We  also  consider 
security of supply impacts within this criterion. 

Page 36 

 
 
b.  Solutions  are  likely  to  deliver  net  benefits  to  society  if  they  improve 
productive and allocative efficiency10, at both Member State and EU level 
and if they result in the right conditions for promoting innovation. 

2.  Investment environment: Do the proposed structures give rise to investible 
propositions? That is, can they attract capital to support material investment in 
long lived assets (by matching risk allocations with investor appetites, delivering 
reasonable returns over appropriate time horizons, providing clarity on long-term 
regulatory treatment and addressing risks associated with stranding)? 

3.  Consumer  protection:  How  might  any  impact  on  net  societal  costs  translate 
into an impact on consumer bills? To what extent do impacts differ by timescale 
(short  vs.  long  run)  or  by  energy  carrier  (electricity  vs.  gas)?  Are  there  any 
impacts on fairness and choice? 

4.  Complexity and timelines: How radical are the institutional changes required 
over today’s market and regulatory framework? What is the risk of unintended 
consequences?  

5.  EU value-added: Is co-ordinated action at EU level likely to be key to delivering 

the benefits identified?  

We assess each potential solution qualitatively against each of the criteria above, using 
a ‘traffic light’ rating system to indicate performance against each criterion. Figure 21 
below sets out how we assign ratings to each assessment criterion.  

10  Productive  efficiency  occurs  when  production  happens  at  the  lowest  possible  cost. 
Allocative efficiency refers to the optimal distribution of resources across the economy. 
It occurs where every good or service is supplied until the point where price is equal to 
the marginal social cost of production (i.e. the incremental cost to society of producing 
an additional unit).  

Page 37 

 
 
                                           
 
 
Figure 21 Evaluation of performance against individual assessment criteria 

Source: Frontier Economics 

4.2.3  TRANSLATING ASSESSMENT CRITERIA INTO RECOMMENDATIONS 

To be included in our list of recommendations, potential solutions must have a positive 
overall balance of societal costs and benefits. This is likely to be the case for solutions 
that directly address an identified market or regulatory failure, to the extent that costs 
of implementation remain manageable. Where several potential solutions are possible 
but are mutually exclusive, we also aim to make clear which solutions might deliver the 
highest net benefit to society.  

In practice, however, policymakers’ decisions on which solutions to adopt will be more 
complicated and will need to consider a wider range of potentially relevant impacts than 
just the overall net benefit to society. The final policy decision will be a complex trade-
off of several factors.   

  To that end, the assessment criteria do include other impacts relevant from an 
economic and policy perspective, such as the impact on consumers. We therefore 
provide information to allow policy-makers to arrive at an alternative evaluation 
based on a possible trade-off between net societal benefits and other relevant 
impacts.  

  However, our criteria do not include other considerations that might be relevant 
to  a  final  policy  decision.  These  include,  for  example,  the  impacts  of  potential 
solutions on fundamental rights or a more detailed analysis of compliance with 
the ‘subsidiarity’ principle.   

In addition, given the scope of this study, neither detailed work on design of individual 
policy options nor a robust quantitative assessment of costs, benefits and distributional 
impacts  of  all  options  have  been  carried  out.  Further  work  will  be  needed  on  these 
aspects. 

Page 38 

 
 
 
 
 
5  LIST OF BARRIERS AND SOLUTIONS FOR SHORT-LISTED BARRIERS 

In this section we:  

  discuss the barriers and gaps identified as part of this study, grouped by high-
level barrier category, and note which are on the long list and which are on the 
short list; and 
for short-listed barriers and gaps, we provide policy recommendations on how to 
address them. 

 

We focus on setting out clearly why and how each factor might act as a barrier or gap 
(i.e. explain which market or regulatory failure is occurring and the impact on the level 
playing  field  in  terms  of  development  of  renewable  and  low-carbon  gases  and  sector 
coupling technologies). After the description of each barrier we indicate whether it was 
retained  on  the  short  list.  In  describing  barriers,  we  sometimes  use  examples  from 
countries reviewed to illustrate the nature of the barrier. However, this is not intended 
to be a complete list of all the countries in which a barrier may be present.  

For  some  of  the  barriers  remaining  only  in  the  long  list  we  give  high  level 
recommendations to feed into further work to overcome these barriers on the European 
or  Member  State  levels.  For  barriers  retained  in  the  short  list  we  discuss 
recommendations in further detail. 

As  apparent  in  Figure  22,  barriers  and  gaps  identified  as  part  of  this  study  may  be 
categorised within five groups, corresponding to the themes set out in section 3.3.4.  

The first two groups include barriers faced by project developers as well as consumers 
of relevant renewable and low-carbon gas and sector-coupling technologies.  

  The  first  group  of  barriers  focuses  on  issues  related  to  the  immaturity  of  the 

relevant technologies.  

  The  second  group  encompasses  issues  arising  from  technology-  and  sector-
specific  regulations  which  may  be  inadequate  to  the  emerging  sector-coupled 
energy market.  

  The  third  and  fourth  barrier  groups  focus  on  infrastructure.  Barriers  in  group 
three arise from the transition from natural gas to a multitude of gas types. 
  Group  four  focusses  on  issues  linked  to  the  increasing  need  of  interlinkage 
between the electricity and gas sectors deploying sector-coupling technologies. 
  Group five deals specifically with the interoperability between different markets. 

Page 39 

 
 
Figure 22 Barrier categories 

Source: Frontier Economics 

The analysis has shown that barriers and gaps include both transitional issues as well 
as steady state issues.  

  Transitional issues are those barriers and gaps that are expected to apply when 
renewable  and  low-carbon  gases  and  sector-coupling  technologies  are  still  in 
early  technology  readiness  levels  and  in  a  phase  during  which  the  costs  are 
expected to continue to reduce as the technologies’ uptake increases. These are 
issues that would be expected to be resolved, either spontaneously or through 
intervention, by the end of the transition – but their prevalence in the transition 
phase may mean that efficiency is not achieved.    

  Steady state issues are those barriers and gaps that are expected to prevail even 

when the relevant technologies have reached maturity.  

The full list of barriers and gaps identified as part of this study is displayed in Figure 23 
below.  

Page 40 

Relative immaturity of relevant technologiesUnlevel playing field due to sector-and technology-specific tariffs and leviesRisk for interoperability across markets and bordersUncoupled and uncoordinated infrastructure planning23451Barrier categories34512Focus on natural gas in infrastructure regulation 
 
 
 
Figure 23 Long list of low-carbon renewables gases and sector coupling technologies barriers and 
gaps 

Source: Frontier Economics   

For  each  of  the  short-listed  barriers,  we  also  present  our  recommended  solutions, 
together  with  the  overview  of  our  qualitative  assessment  of  their  relevance.  The 
solutions we assess can also be grouped into five categories: 

Page 41 

 
 
 
 
  Interventions  via  climate  and  renewable  policy,  and  support  for 
innovation:  this  group  of  solutions  is  designed  to  address  barriers  and  gaps 
related  to  the  relative  immaturity  of  sector  coupling  and  low-carbon  and 
renewable gases technologies; 

  A  regulatory  toolbox  to  address  cost  recovery  issues:  this  group  would 
serve  to  address  barriers  and  gaps  from  group  2,  that  is  to  say  issues 
contributing to an unlevel playing field across technologies; 

  A  number  of  changes  to  market  design  and  charging  arrangements  to 
make them more fit-for-purpose in the face of the expected changes in 
the  sector:  these  would  address  issues  stemming  both  from  the  relative 
immaturity  of  relevant  technologies,  and  the  historic  focus  on  natural  gas  in 
infrastructure regulation; 

  The provision of increased clarity on access to infrastructure would also 
aim to overcome barriers and gaps stemming from the historic focus on natural 
gas in infrastructure regulation; and 

  The 

co-ordinated 

facilitation  of 

infrastructure  planning  and 
decommissioning, which would be expected to help achieve a level playing field 
across  technologies,  avoid  the  risks  of  uncoupled  and  uncoordinated 
infrastructure  planning,  as  well  as  the  risks  related  to  interoperability  across 
markets and borders. 

Figure 24 below provides an overview of how the categories of solutions described above 
map to the high-level categories of barriers.  

Figure 24 Overview of barrier categories and solution categories 

Source: Frontier Economics 

In the following sub-sections, we describe the individual barriers identified and solutions 
assessed in more detail.  

Page 42 

Risk for interoperability across markets and bordersUncoupled and uncoordinated infrastructure planningFocus on natural gas in infrastructure regulationUnlevel playing field due to sector-and technology-specific tariffs and leviesRelative immaturity of relevant technologiesClimate / renewable policy and support for innovationFit for purpose market design and charging arrangementsRegulatory toolbox to address cost recovery issuesCo-ordinated infrastructure planning and decommissioningClarity on access to infrastructureBarriersSolutions/recommendations35421 
 
 
5.1  RELATIVE  IMMATURITY  OF  SECTOR  COUPLING  AND  RENEWABLE  AND  LOW-

CARBON GASES TECHNOLOGIES 

The first category of barriers relates to the immaturity of the relevant technologies. By 
construction,  most  of  these  barriers  are  expected  to  be  problematic  in  the  transition 
period.  In  the  steady  state,  i.e.  as  we  approach  2050,  a  number  of  technologies  are 
expected to have reached maturity and may have overcome some of the barriers11.  

Figure 25 gives  an overview  of the  barriers identified in this  category, as  well as  the 
potential solutions assessed for the short-listed barriers.  

Figure 25 
for short list barriers 

Overview of short and long list barriers in category 1 and the solutions assessed 

Source: Frontier Economics 
Note: Barriers outlined light red belong to the transition, barriers outlined red are steady state 
barriers. 

Transition - Producer level  

The following issues have been identified which may be reducing appetite from project 
developers in the transition phase. 

11 We note that new technologies may arise on an ongoing basis and face transitional 
issues later than those technologies that are already envisaged to be at play. 

Page 43 

Innovation / learningFirst-mover disadvantage –high infrastructure connection costsRelative immaturity of relevant technologiesClimate / renewable policy for innovationSupport for R&D / pilot funding1.1.1Regulatory clarification/enabler -grid operators able to invest/own P2G for R&D / pilots1.1.51.1Clarify TSOs can invest/own storage/PtG, subject to ‘market test’ –allow ownership subject to infeasibility of market-driven investments1.1.4Ongoing support promotes competition and market integration1.1.2EU-wide gas-sector specific targets1.1.3Shallow connection costs (transitional)1.2.1Targeting of regional reinforcement costs1.2.2Solutions assessedfromcategories:Barriercategory:Fit for purpose market design and charging arrangementsLack of liquid market for feedstock (biomass)Lack of know-how / engagement from players controlling process inputsBehavioural or information barriers to domestic switchingSector-specific targets biasing choice of technologies by end consumersBehaviours to switching in the industry sectorAffordability issuesLack of harmonised sustainable investment definition for sector couplingUncertain ability to monetise renewable / low-carbon characteristics1.21.31.41.51.61.71.81.91.10 
 
 
 
                                           
 
 
5.1.1  LACK OF INTERNALISATION OF POSITIVE EXTERNALITIES FROM INNOVATION 

/ LEARNING 

The  development  of  immature  technologies  will  benefit  not  only  the  developer  or 
investor  but  also  other  developers  and  overall  society.  Knowledge  and  learning  from 
innovation  will  not  only  benefit  the  stakeholders  undertaking  and  financing  the 
investment but will spread more widely, i.e. will have a positive externality. This applies 
at different stages of the technology development process:  

  Fundamental  research    is  used  to  acquire  new  knowledge  of  underlying 
foundations of phenomena and observable facts, without any direct commer cial 
application or use in view. 

  The results of this research need then to be applied to the development of new 
concepts and processes (in the context of this report, the development of new 
sector  coupling  technologies,  or  new  ways  of  producing  renewable  and  low-
carbon gases).  

  At  the  demonstration  phase,  new  technologies  are  tested  in  a  commercial 
setting. The objective may be to evaluate how the technology performs or to see 
how it interacts with the environment or system in which it operates (for example 
testing hydrogen injection in existing gas infrastructure). 

  During the deployment phase, the focus is on large-scale roll-out of a technology 
and achieving cost reductions as supply chains and expertise develop. Research 
the  deployment  (and 
and  development  (R&D)  may  continue  during 
demonstration)  phases,  for  example  with  the  aim  of  helping  to  identify 
incremental improvements to production processes. 

As a result of the above, although the costs borne by the developer12 may be lower than 
the  benefit  to  society,  they  are  likely  to  be  higher  than  the  benefit  the  individual 
developer can retrieve. This may lead to underinvestment in some of these technologies. 
This is a market failure common to all countries and technologies. 

This barrier or gap has been retained in the short list of issues and potential solutions 
are therefore assessed below.  

Recommendation 
externalities from innovation / learning 

lack  of 

for 

internalisation  of  positive 

The direct way of addressing this market failure would be support for Research and 
Development  (R&D),  pilots  or  demonstration  projects  and,  potentially,  beyond 
that, support for further deployment following the demonstration phase to help 
achieve  potential  ‘learning-by-doing’  benefits  (cost  reductions  driven  by  increased 
deployment). Public financial support can help boosting the innovative activity carried 
out  by  the  market,  in  instances  where  there  are  positive  spillovers  which  are  not 
considered  by  private  investors  and  where  this  results  in  the  market  under-investing 
compared to the socially optimal level. Support for R&D, pilots and deployment of low-
carbon gases  comes  at  a cost in the near term but can help to deliver reduced  costs 
associated with decarbonisation over the longer-term.   

12  The  study  did  not  develop  own  cost  analysis.  Existing  evidence  in  this  area  was 
reviewed as part of the work for Objectives 1 and 2, and is presented in the Intermediate 
Report.  

Page 44 

 
 
                                           
 
 
 

In deciding on an approach to technology support, there will be a trade-off to be 
evaluated between ensuring that funding is directed towards technologies that 
have  greater  promise  (for  example,  in  terms  of  future  cost  and  ability  to  be 
deployed at scale) and avoiding closing off other technology options for the future 
by denying them support or otherwise discriminating against them. Robust policy 
design  can  mitigate  the  risk  that  too  much  support  is  granted  to  technologies 
with limited promise.  

 

  Support could come from individual Member State budgets, subject to State aid 
rules. Support at Member State level could help promote a diversity of options, 
since  it  is  possible  that  certain  technologies  may  be  more  relevant  in  some 
Member States than in others. . 
In addition, support could come from EU-wide funding mechanisms (such as the 
Innovation Fund under the EU ETS). Support at EU level could be desirable to 
the extent Member States have incentives to free-ride on the efforts of others. 
This  may  be  the  case  where  the  benefits  of  technology  development  extend 
beyond  the  Member  State  (to  other  regions  in  the  EU)  and  where  individual 
Member  States  may  find  it  too  risky  to  invest  by  themselves  or  where  their 
finances are significantly constrained. 

Another intervention to accompany the development of innovative sector coupling and 
low-carbon  and  renewable  gases  technologies  is  ongoing  support.  How  ongoing 
support is granted to power-to-gas projects is an important consideration. The benefits 
of ongoing support to immature technologies will be enhanced if support is granted 
in ways that promote competition and market integration. This is particularly the 
case where support is not through central EU funding mechanisms, but instead granted 
by individual Member States. 

  EU rules for support for renewable electricity13 promote competitive tendering of 
support,  technology-neutrality  (striking  a  balance  between  the  benefits  of 
competition and the need to promote emerging technologies) and cross-border 
participation in support schemes. Similar rules for gases would help to promote 
the  uptake  of  lower-cost  solutions.  Potential  risks  to  investors  from  increased 
competition in the allocation of support can be mitigated if the award of financial 
support happens at a sufficiently early stage of project development 

  EU  rules  also  promote  balancing  responsibility  and  market  integration  of 
renewable  electricity  installations.  Provided  that  players  can  manage  the  risks 
associated  with  balancing  responsibility  (for  example  through  short-term 
trading),  this  represents  an  efficient  allocation  of  risk,  as  parties  would  be 
incentivised to reduce the costs they impose on the wider system. Similar rules 
for  gases  would  help  to  reduce  the  costs  of  operating  the  system,  though  the 
benefits  may  be  lower  compared  to  electricity,  given  that  flexibility  within  the 
gas system helps to limit balancing costs (due to the ability to vary linepack, the 
amount of gas stored within the system). The corollary of this, on the other hand, 
is that the risks to market participants of balance responsibility would be lower 
in gas than in electricity. Participants are typically only required to balance their 
portfolios over daily timescales, making the presence of very short-term markets 
(e.g.  hourly)  less  important.  Clear  rules  around  congestion  management  for 
(gas)  injection  (see  section  5.3.4)  may  also  be  a  pre-requisite  for  balance 
responsibility. 

13 Including the Commission’s Guidelines on State aid for environmental protection and 
energy (‘EEAG 2014’), Directive 2018/2001 on the promotion of the use of energy from 
renewable  sources  (‘RED  II’)  and  the  revised  Electricity  Regulation  (Regulation 
2019/943 on the internal market for electricity, OJ L 158, 14.6.2019, p. 54–124). 

Page 45 

 
 
 
                                           
 
 
  Exemptions from competitive tendering and full market integration are possible 
for small installations. Similar rules could be adopted for support for renewable 
and low-carbon gas technologies.  

Several stakeholders have also called for  (binding) EU-wide (gas-sector specific) 
targets,  for  renewable  and/or  low-carbon  gases.  While  such  targets  would  not 
directly address the innovation market failure, they could be a driver for policies (such 
as  financial  support)  that  might  address  it.  Hence,  we  assess  this  potential  solution 
under  the  ‘innovation’  barrier.    In  our  assessment,  we  consider  that,  assuming  the 
existing  governance  and  climate  policy  framework  is  strong  enough  to  spur  Member 
States  towards  meeting  long-term  climate  and  renewable  energy  targets,  then  gas 
sector-specific targets risk simply increase the costs of meeting the broader targets14 
by reducing EU and Member State flexibility. A sector-specific target is only likely to be 
efficient if: 

 

 

it addresses a barrier to political engagement that can otherwise not be solved 
through  existing  (or  potential  reforms  to)  Energy  Union  governance 
arrangements; or 
there  were  to  be  a  specific  political  objective  to  further  the  development  of 
renewable and low-carbon gases. 

The solutions above address issues related to financing but not necessarily the question 
of  who  is  best-placed  to  carry  out  the  required  innovative  activity.  In  that  respect, 
several  stakeholders  have  called  for  grid  operators  being  able  to  own,  operate  or 
otherwise participate in power-to-gas projects. This could be a signal that stakeholders 
do not perceive that there is sufficient clarity on whether network operators would be 
able to operate or participate in research-stage or pilot power-to-gas projects, or that 
they  believe  exemptions  to  the  usual  EU  rules  on  ‘unbundling’  are  justified  for  such 
projects. We have assessed the relevance of allowing network operator ownership 
(or  involvement  in)  research-stage  or  pilot  power-to-gas  projects in  specific 
circumstances. By ‘pilot’, we refer to demonstration-stage power-to-gas projects with 
the primary objective of studying the impacts of power-to-gas facilities on the electricity 
and gas systems. Such projects are likely to be limited in size and number.  

This may necessitate clarifying EU legislation in relation to unbundling rules but would 
not  be  expected  to  reopen  the  principles  of  unbundling  (as  network  operator 
involvement  would  be  tied  to  specific  circumstances  and  types  of  projects).  To  strike 
the right balance in this regard, we would recommend that the following considerations 
should be taken into account: 

  The  involvement  of  network  operators  in  such  projects  may  be  particularly 
important  to  the  extent  that  understanding  technical impacts  on  the  networks 
themselves  (for  example,  in  terms  of  gas  quality  or  in  terms  of  the  potential 
system cost savings delivered) may be an important subject of study. 

  Such  ‘experimental’  projects  would  not  be  expected  to  have  a  commercial 
purpose.  Assuming  projects  remain  limited  in  size,  it  may  be  difficult  (or 
disproportionate) to devise and agree on commercial arrangements that would 
allow  other  parties  to  own  and  operate  power-to-gas  facilities  while  allowing 
network  operators  (potentially  both  on  the  electricity  and  gas  side)  to  keep  a 
central  role  in  the  technical  feasibility  studies.  Addressing  this  co-ordination 

14 This will be the case irrespective of how the sector-specific target is defined (e.g. in 
terms of production or in terms of consumption).   

Page 46 

 
 
 
 
                                           
 
 
barrier  could  (in  conjunction  with  ensuring  sufficient  financing  of  innovative 
activity) therefore also help to ensure an optimal level of innovation takes place.  
  Ownership could, in these special circumstances be allowed by either electricity 
or  gas  network  operators.  However,  given  power-to-gas  projects  would  have 
effects  on  both  systems,  an  affected  network  operator  should  have  the 
opportunity to provide feedback to the operator leading the project on its design 
(and location), before it goes ahead.  
It would be important to ensure that the projects remain targeted in scope (i.e. 
limited to research and pilot projects) and that solutions are found (such as time 
limits for TSO ownership15) to avoid potential longer-term negative effects on the 
functioning of competitive and market-based investments.  

 

 

  Review and approval of such projects by the NRA would play an important role 
in  minimising  the  potential  negative  consequences  on  commercial  investment 
activity and maximising the potential benefits to the wider market. 
It would also be important to ensure that any learning from such projects (funded 
publicly  or  through  regulated  network  tariffs)  is  made  available  to  market 
participants.  This  would  further  contribute  to  reducing  the  risk  that  market 
participants  are  deterred  from  engaging  in  the  market  by  the  presence  of 
regulated competitors.  

We  consider  the  relevance  of  ownership  of  power-to-gas  projects  by  grid 
operators  may,  even  in  the  steady  state,  contribute  to  addressing  potential  co-
ordination  barriers  preventing  potential  investors  from  fully  capturing  wider  system 
benefits in addition to commercial benefits: 

  As  explained  above  (section  4.1.2)  investment  will  reach  efficient  levels  if 
investors can monetise not just commercial benefits, but also any benefits they 
bring for the wider system (and which may relate to regulated revenues, e.g. for 
the provision of certain ancillary and system services). 
It  may  in  principle  be  possible  to  design  arrangements  (such  as  locational 
network  signals  or  complete  markets  for  flexibility)  that  allow  investors  to 
capture such wider benefits. Such arrangements may even already exist in many 
jurisdictions (for example, market-based re-dispatch in electricity or differential 
network charging based on location).  

 

  However, the task of ensuring a fully comprehensive and efficient set of locational 
signals  across  both  electricity  and  gas  networks  to  ensure  market-driven 
investment  may  (depending  on  the  likely  scale  of  investment  required)  be 
complicated.  

  While there is therefore a risk of ‘policy failure’ in any administrative assessment 
of the extent to which power-to-gas projects may bring system benefits, there 
is equally a risk that locational signals are not perfectly designed and that this 
may preclude certain power-to-gas investments that would be desirable from a 
system perspective.  

  Ownership of power-to-gas facilities may therefore allow investment in power-
to-gas facilities that the market may not deliver (if such projects are economically 
desirable but would not go ahead on a merchant basis). 

However,  ownership  of  power-to-gas  projects  by  grid  operators  in  the  steady  state 
would not be without risks and it is important these are effectively managed: 

15  We  note  that,  by  construction,  the  expectation  would  be  that  in  most  cases  the 
technology used in pilot projects would become obsolete. 

Page 47 

 
 
 
 
                                           
 
 
  First, merely allowing network operators to own or operate power-to-gas facilities 
may not be sufficient to ensure efficient levels of investment: network operators 
would  need  to  face  incentives  (see  sections  5.4.2  and  5.4.3)  to  achieve  cost 
savings that drive them to carry out such investments. 

  Depending  on  network  operators’  incentives,  the  location  proposed  for  any 
project  may  not  be  optimised  across  both  electricity  and  gas  systems.  Co-
ordination  and  communication  between  electricity  and  gas  network  operators 
(see section 5.4.3) would be important to ensure benefits are maximised. This 
may need to be incentivised through regulatory arrangements. 

  To  result  in  efficient  levels  of  investment,  projects  would  need  to  be  able  to 
capture commercial benefits as well as system benefits. Given this, there may 
be  concerns  from  market  players  that  network  operators  may  distort  or  even 
dominate the power-to-gas sector entirely, deterring market based investment. 
As above  for investment in pilot projects, NRAs may play an important role in 
ensuring that network operators are only allowed to carry out investments only 
in situations in which pilot projects are desirable and where changes to market 
design are not feasible or proportionate and in which market players cannot be 
attracted to invest (for example by applying a ‘market test’).  

Figure 26 below summarises our assessment of the options set out above. In summary, 
we  would  recommend  taking  forward  the  following  solutions  (for  more  detailed 
assessment and policy design work): 

 

support  R&D,  pilots  or  demonstration  projects  and,  potentially,  beyond  that, 
support for further deployment following the demonstration phase; 

  ensuring that any ongoing support is granted in ways that promote competition 

and market integration; 

  allowing network operator ownership (or involvement in) research-stage or pilot 

power-to-gas projects but only in specific circumstances; and 

  allowing network operator ownership of power-to-gas only in situations where it 
is  difficult  (or  disproportionate)  to  ensure  market  signals  convey  all  possible 
system  benefits  (e.g.  the  benefits  of  the  specific  location  of  a  facility)  well 
enough. 

Figure  26  Assessment  of  potential  solutions  to  address  lack  of  internalisation  of  positive 
externalities from innovation and learning 

Source: See Appendix C for further detail on the assessment. 

Page 48 

 
 
 
 
 
 
 
5.1.2  LACK OF LIQUID MARKET FOR FEEDSTOCK (BIOMASS) 

A  number  of  renewable  and  low-carbon  gases  technologies  rely  on  biomass  inputs. 
Biomass is typically produced in decentral locations such as farms. Sources of biomass 
may not be part of a liquid market, where inputs can be traded at minimal transaction 
costs.  Therefore,  developers  run  the  risk  of  default  of  input  source,  as  in  an  illiquid 
market it may be difficult to find another source of the input. This issue has been raised 
in France16. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.3  LACK OF KNOW-HOW / ENGAGEMENT FROM PLAYERS CONTROLLING PROCESS 

INPUTS 

Some players have historically only engaged as energy consumers but hold the potential 
input  for  the  production  of  renewable  energy,  such  as  biomass,  CO2,  wind  or  solar 
potential. Lack of know-how or engagement from the stakeholders hinder the effective 
use of inputs and the effective realisation of potentials. This barrier has been raised in 
France. 

Further,  this  barrier  is  a  consequence  of  the  one  above,  as  an  illiquid  market  will 
hamper: 

  access to banking funds; and 
  access to equity, especially for players like biomass farmers that have historically 

not been very engaged in the energy market. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.4  FIRST MOVER DISADVANTAGE - HIGH INFRASTRUCTURE CONNECTION COSTS 

INCLUDING ‘DEEP’ COSTS 

Developers  of  renewable  and  low-carbon  gases  and  sector  coupling  technologies 
typically  face  connection  costs,  charged  by  network  operators  to  establish  a  physical 
connection between the site and the existing gas network.  

There is no harmonised practice for connection charging in gas across the EU, but rather 
a range  of practices.  Schematically, these practices are typically articulated around a 
sequence of considerations: 

  First, gross connection costs are calculated. These are costs that would need to 
be incurred by the infrastructure operator in order to connect and accommodate 
load served to the site and/or production injected from the site. These costs can 
be calculated as only the costs of those assets required to establish the physical 

16 As mentioned above in Figure 26 Assessment of potential solutions to address lack of 
internalisation  of  positive  externalities  from  innovation  and  learning  we  give  non-
exhaustive country examples were a barrier has been raised in interviews with country 
stakeholders. This, however, does not necessarily mean that this barrier does or will not 
occur in other countries.  

Page 49 

 
 
                                           
 
 
connection from the  site to the  existing grid  – hereafter ‘shallow’ costs.  Gross 
connection costs may also be calculated to include any other incremental, often 
labelled  ‘reinforcement’  costs  to  be  incurred  on  the  existing  infrastructure  to 
accommodate the presence of the site on an ongoing basis. In those instances 
gross connection costs are said to be ‘deep’. 

  Second,  the  share  of  gross  connection  costs  to  be  borne  by  the  site  is  set.  In 
several Member States, an “economic test” is applied whereby the proportion of 
the resulting investment costs to charge to the site will reflect gross connection 
costs  net  of  expected  future  tariff  revenue  from  the  site.  This  test  may  be 
performed  on  a  site-by-site  basis.  In  other  instances,  a  fixed  share  of  gross 
connection costs may be applied standardly across sites.  

It  may  be  the  case  that  reinforcements  are  triggered  by  one  site  and  then  allow 
accommodating additional sites (e.g. where grid capacity is incremented). Where gross 
connection  costs  include  deep  costs,  and  where  sites  are  required  to  bear  a  non-null 
share of gross connection costs, then there is a risk that the first connecting site will 
bear the majority of these costs, even if then further sites go on to connect. This can 
deter the first move from happening. 

The optimal configuration of reinforcement will also often depend on volume and location 
of  connections  in  the  medium  term.  It  will  therefore  not  be  efficient  to  deal  with  an 
incremental connection request with piecemeal reinforcement. However it would equally 
not  be  efficient  for  the  first  connecting  site  to  bear  the  full  cost  of  reinforcements 
designed to be optimal given expected further connections.  

This barrier materialises in those Member States where a methodology exists today to 
set connection costs for low-carbon and renewable gases sites. In those countries where 
no such methodology exists, lack of clarity around the connection charging approach to 
be  applied  in  the  future  may  also  be  an  issue  (it  would  leave  project  developers 
hypothetising around costs to be borne for future projects, undermining confidence in 
business plans).  

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below. 

Recommendation for first mover disadvantage high infrastructure 
connection costs including ‘deep’ costs 

By  construction,  addressing  this  barrier  would  require  amending  the  approach  to 
determining connection costs to be borne by project developers, with a view to reducing 
(or  even  eliminating)  the  first  mover  disadvantage,  compared  to  subsequent 
connections.  There  is  a  spectrum  of  potential  solutions  to  achieve  this.  For 
instance, the share of gross connection costs to be borne by the site may be 
set by taking into account: 

  expected tariff income from a group of connections (as opposed to a single 

connection); or 

  expected tariff income from  projected  future connections in the same  area 

(as opposed to focussing only on a single connection) 

A a result, connections might be made if: 

 

 

tariff  income  exceeds  a  certain  percentage  (not  necessarily  100%)  of 
reinforcement costs; 
tariff income from a group of connections (as opposed to a single connection) 
exceeds reinforcement costs; or 

Page 50 

 
 
 
  expected tariff income (from projected future connections in the same area) 
exceeds  reinforcement  costs  (as  opposed  to  focussing  only  on  a  single 
connection).  

Each of the above options would result in the first connecting site in a given area having 
to bear less than 100% of the reinforcement costs it might generate, thereby reducing 
(or  even  eliminating)  the  first  mover  disadvantage,  compared  to  subsequent 
connections.   

At the same time, they all still include locational signals (to varying degrees) – at the 
level  corresponding  to  the  geographical  reach  of  the  group  of  connections  taken  into 
account  in  the  calculations.    Overall,  therefore,  such  options  have  the  potential  to 
encourage the development of low-carbon  and renewable gases while minimising the 
risk of incentivising uptake of expensive connections.   

There may however be some complexities: 

  There may still be a question as to the degree to which reinforcement costs 
specific  to  a  particular  connection  should  be  socialised  or  targeted  to  the 
individual connection in question. 

  Some models may not guarantee that infrastructure operators recover their 
expenditure.  Outstanding  costs  would  be  expected  to  be  socialised  within 
allowed  revenue,  with  a  distortion  in  the  distribution  of  costs  amongst 
network users. 

  Models based  on projections of potential gas connections in a given region 
could end up becoming a ‘self-fulfilling prophecy’ (since, other things equal, 
charges will tend to be lower in regions with higher estimated connections).  
This may lead to inefficiency if alternative projections might have led to more 
connections taking place in regions with lower reinforcement costs.  

While  considering  only  shallow  costs  when  assessing  gross  connection  costs 
(potentially  on  a  transitional  basis)  would  also  address  the  first-mover  disadvantage 
barrier  it  may  not  be  the  most  appropriate  solution.  The  main  risk  is  that  it  would 
encourage  developers  to  connect  in  locations  with  high  reinforcement  requirements, 
increasing the overall costs associated with decarbonisation.   

Regardless of the precise approach taken, it will be important to ensure that decisions 
on  connection  charging  and  handling  connection  requests  are  co-ordinated  across 
energy carriers (to avoid potentially creating new distortions between them) and levels 
of the network (this is discussed further below in sections 5.4.2 and 5.4.3). For example, 
if  electricity  connection  charges  reflected  ‘deep’  costs  but  gas  connection  charges 
reflected ‘shallow’ gross connection costs, power-to-gas facilities might have incentives 
to connect predominantly to areas where electricity connection charges were cheap, but 
which could require significant gas network reinforcement costs. 

In addition, to the extent that cross-border participation in support schemes becomes a 
reality  (see  section  5.1.1  above),  a  degree  of  regional  co-ordination  on  connection 
charging approaches may also be appropriate to ensure efficiency.  

Figure 27 below summarises our assessment of the options set out above. In summary, 
we  would  recommend  taking  forward  connection  charging  approaches  that  avoid  the 
first-mover  disadvantage  while  still  preserving  locational  signals  (for  more  detailed 
assessment and policy design work). 

Page 51 

 
 
 
 
 
 
 
Figure 27 Assessment of potential solutions to address a possible ‘first mover disadvantage’ with 
deep connection charging  

Source: See Appendix C for further detail on the assessment. 

Transition - Consumer level 

The achievement of the transition may also face barriers on the energy consumers’ side. 

5.1.5  BEHAVIOURAL  OR  INFORMATIONAL  BARRIERS  TO  ACCEPTANCE/SWITCHING 

FOR HOUSEHOLD CONSUMERS 

Household  consumers’  investment  and  consumption  preferences  and  decisions  are 
based  on  costs  and  softer  factors  such  as  safety  standards  and  sustainability 
characteristics. The following issues are relevant in several of the countries reviewed: 

  Regarding  cost  information,  it  is  key  that  consumers  are  able  to  correctly 
compare  the  costs  of  different  technology  options.  For  instance,  there  is  an 
information barrier if the principles / structure / cost components making up the 
bill of the different energy carriers are not comparable.  

  Softer technology characteristics such as perception of safety and sustainability 
may have the potential to increase consumers’ readiness to accept and switch to 
climate  neutral  technologies.  However,  this 
is  often  only 
incompletely available for consumers. One example is that, in some countries, 
energy  in  gaseous  form,  especially  hydrogen,  is  perceived  as  more  dangerous 
than  other  energy  carriers.  However,  this  may  be  due  to  a  relative  lack  of 
awareness of  ensured safety levels. Another example is that consumers  might 
make a more conscious decision regarding which gases to use if they were more 
aware of the different climate implications of different gases. 

information 

Further, even when all relevant information is available, behavioural barriers may arise 
that prevent switching decisions for cost optimisation.  

  Household  consumers  will  likely  not  constantly  incur  search  costs  looking  for 
information  to  decide  whether  to  switch  to  a  technology  or  not.  Typically, 
consumers will only look for alternatives to currently-installed technology at the 
end of its lifetime, for instance when a heating appliance needs to be renewed. 
However,  sometimes  it  may  be  important  for  society  that  consumers  make  a 
switch  away  from  a  technology  before  the  end  of  the  lifetime  of  existing 
appliances,  for  example  to  avoid  harmful  emissions.  This  may  be  the  case  for 
instance  when  switching  from  a  less  efficient  heating  appliance  like  a  normal 
heating boiler to a more efficient condensing boiler or switching from a natural 
gas supplier to a renewable and low-carbon gas supplier. However, consumers 
may  need  to  be  pointed  to  these  advantages,  as  they  will  not  necessarily 
themselves look for them. 

  Consumers may abstain from switching even when it is economically beneficial 
because they prefer to stick to what they currently have and what they already 
know.  Another  reason  why  households  may  stick  with  current  technologies  is, 
that they may weigh the short run costs they  have from  switching to the new 
technology more than the long run benefits. 

Page 52 

 
 
 
 
 
This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.6  BARRIERS TO SWITCHING IN THE INDUSTRY SECTOR 

For industrial consumers the barriers to switching may be different than for households. 
Barriers  may  be  less  behavioural  in  nature  to  the  extent  that  industrial  sites  will  be 
managed with a view to optimising costs on an ongoing basis, and will not shy away 
from incuring time/information search costs in order to optimise the technology portfolio 
even within the lifetime of current installations.  

However,  technical  barriers  may  arise.  While  the  energy  transition  is  a  continuous 
development towards the climate targets in 2050, for industrial players the decision to 
switch to renewable or low-carbon gases may be a binary, i.e. all or nothing, decision. 
This is for example the case if an industry site decides to switch from natural gas as an 
energy source to renewable or low-carbon hydrogen. One barrier may be the perceived 
risk that the necessary  amount of  renewable  or low-carbon gas will not be available.  
This scarcity risk may arise due to the mere volume required for industrial processes. 
This barrier has been raised in Germany. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.7  AFFORDABILITY ISSUES 

Some technologies are expensive for (certain groups of) consumers – either because of 
their  upfront  investment  costs  or  their  ongoing  costs  –  which  may  be  a  barrier  to 
reaching efficient levels of their deployment.  

Regulation  may  exacerbate  affordability  issues.  For  example,  in  2010,  in  Baden-
Würtemberg,  Germany,  the  regional  government  introduced  an  obligation  on 
homeowners to source 15% of heat requirements from renewable sources such as solar 
thermal  energy,  heat  pumps  or  biofuels,  whenever  replacing  existing  heating 
equipment.  Homes  heated  by  gas  could  fulfil  the  criteria  by  using  a  certain  share  of 
renewable gas. However, that share was given credit only if combined with a micro-CHP 
facility rather than for example the possibility to use a cheaper gas condensing boiler. 
Many  homeowners,  perceiving  high  up-front  costs  micro-CHP,  switched  to  new  (less 
expensive)  conventional  boilers  just  before  the  law  was  introduced.  Others  have  not 
switched  the  heater  since  the  law  became  effective.  As  a  result,  the  number  rate  of 
heating  equipment  replacements  decreased  significantly  since  the  introduction  of  the 
law. Thus, the policy fell short in its ambition to boost renewable heating.  

Further,  there  is  a  first-mover  disadvantage  for  consumers  in  the  transition  as  cost 
reduction with increasing scale of the production or network coverage can be expected. 
Therefore, it may be difficult to find early adopters of technologies. For instance,  

Page 53 

 
 
 
 

 

the Bulgarian government aims at 30% of households having access to natural 
gas  by  202017  to  decrease  the  high  share  of  coal  and  solid  fuels  use  (34% 
compared  to  a  16%  EU  average).  However,  it  is  down  to  prospective  retail 
customers to pay for equipment and connection costs from the nearest gas point, 
which – especially in view  of the low network  density18 - is a financial barrier. 
Grants  are  in  place  to  help  households  pay  for  gas  connection  and  some 
equipment costs19, but take up of the programme remains low. 
the roll out of hydrogen may be an option in the future. Incremental roll out by 
region affects consumers differently depending on the geography and time. Early 
in the transition, hydrogen will cost more than later on, once technology matures. 
These differences in costs will result in both regional and temporal inequalities in 
the costs faced by consumers. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.8  SECTOR-  AND  TECHNOLOGY-SPECIFIC  TARGETS  BIASING  CHOICE  OF 

TECHNOLOGIES BY END CONSUMERS 

Policies may bias consumers’ choice between technologies, if they are designed in a way 
that  favours  some  technologies.  An  example  of  a  technology  specific  policy  with 
potentially  strong  impact  on  end-user  choices  is  renewable  and  low-carbon  gas  as  a 
factor in building codes. Currently building codes often treat electricity-based heating 
devices  as  climate-neutral,  even  when  electricity  is  generated  from  fossil  sources. 
Conversely, gas appliances like gas boilers are not regarded as climate neutral, even if 
renewable and low-carbon gas is used20.  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

of 

till 

27. 

page 

2020, 

Bulgaria 

Through 

Available 

the  programme  DESIREE  Gas,  co-funded  by 

EWRC, 2018, Annual Report to the European Commission, page 47. Available at 

Ministry  of  Economy,  Energy  and  Tourism,  2011,  The  Energy  Strategy  of  the 
at 

17  
Republic 
https://www.me.government.bg/files/useruploads/files/epsp/23_energy_strategy2020
%D0%95ng_.pdf 
18  
https://www.ceer.eu/documents/104400/6319351/C18_NR_Bulgaria-
EN.pdf/62db8c49-4510-b6f0-224c-03794b1bb304  
19  
https://desireegas.bg/en/about-the-project  
20 Another example is renewable gases as an option to achieve car fleet targets: Fleet 
targets  (Directive  2009/33/EC)  incentivise  efforts  to  tackle  carbon  emissions  in  the 
transport sector. However, as it stands, they adopt only a “tank-to-wheel” perspective 
and fail to examine the whole value chain from “well-to-wheel”. In other words, fleet 
targets  may  fail  to  account  for  the  differing  carbon  intensities  of  the  fuels  used, 
triggering the following regulatory failure: On the one hand, an electric vehicle counts 
as climate-neutral within a fleet, even if the electricity was generated from 100% coal 
and generated CO2 emissions. On the other hand, a car with a gas combustion engine 
driven  by  100%  renewable  gas,  e.g.  synthetic  methane,  counts  as  one  emitting  CO2 
emissions of natural gas, despite the fact the CO2 emitted from the engine was extracted 
from the environment beforehand to generate a climate-neutral gas. 

the  EU.  See 

Page 54 

 
 
 
                                           
 
 
Steady state – producer level 

While most of the barriers in this group are of transitional nature, a barrier has been 
identified that may persist even after technologies have reached scale and maturity. 

5.1.9  UNCERTAIN  ABILITY  TO  MONETISE  RENEWABLE  / 

LOW-CARBON 

CHARACTERISTICS 

Producers may face uncertainty on the  extent to which  they will be able to  monetise 
and  trade  renewable  and  low  carbon  characteristics  in  the  long  run.  This  would  be 
expected to impede their willingness to incur investment costs. The barrier persists even 
after  

  on the production side, the technology is produced at a large scale and cost 

reductions have been realised. 

  on  the  consumption  side,  the  technology  is  deployed  and  consumers  are 

willing to pay for the renewable and low-carbon characteristic. 

The  uncertainty  to  monetise  and  trade  in  the  steady  state  context  may  stem  from 
technical  factors  as  the  differences  in  technical  standards  which  may  hamper  the 
ability to trade across regions; and policy factors such as the following. 

To seek a higher price for renewable or low-carbon gases, their producers need to be 
able  to  certify  the  renewable  (or  low-carbon)  characteristic  of  the  gas  produced. 
Guaratees of Origin (GoO) are required to enable them to do so.  

The revised Renewable Energy Directive (RED II) reflects some crucial points.  Recital 
55 reflects the need for GoO21. Also recital 59 of the RED II reflects that GoO should not 
only  be  in  place  for  renewable  electricity  but  also  for  other  energy  forms,  such  as 
hydrogen produced from renewable electricity22. 

However,  RED  II  is  seen  to  leave  scope  for  interpretation.  While  it  makes  important 
suggestions,  there  is  the  perceived  risk  that  the  way  in  which  Member  States  will 
implement GoO schemes will not always adequately reflect the contribution of various 
technologies to environmental goals. For instance, for stakeholders producing renewable 
gas via electrolysis, it is important whether renewable electricity from the grid can count  
as being renewable or not.  

Some  stakeholders  believe  that  Article  27,  paragraph  3  of  RED  II  should  in  principle 
allow this provided certain conditions are met: 

“Electricity that has been taken from the grid may be counted as fully renewable 
provided that it is produced exclusively from renewable sources and the renewable 

21 “Guarantees of origin issued for the purposes of this Directive have the sole function 
of showing to a final customer that a given share or quantity of energy was produced 
from renewable sources. A guarantee of origin can be transferred, independently of the 
energy to which it relates, from one holder to another. However, with a view to ensuring 
that a unit of renewable energy is disclosed to a customer only once, double counting 
and double disclosure of guarantees of origin should be avoided.” 
22 “Guarantees of Origin currently in place for renewable electricity should be extended 
to cover renewable gas. Extending the guarantees of origin system to energy from non-
renewable  sources  should  be  an  option  for  Member  States.  This  would  provide  a 
consistent means of proving to final customers the origin of renewable gases such as 
biomethane and would facilitate greater cross-border trade in such gases. It would also 
enable the creation of guarantees of origin for other renewable gases such as hydrogen.” 

Page 55 

 
 
                                           
 
 
properties and other appropriate criteria have been demonstrated, ensuring that the 
renewable properties of that electricity are claimed only once and only in one end-
use sector.” 

However, many stakeholders face uncertainties regarding: 

 

 

the  ways  in  which  the  renewable  character  of  electricity  consumed  may  be 
demonstrated, for example whether a Power Purchasing Agreement between a 
renewable electricity generation facility and an electrolyser would be  sufficient 
(as opposed toa direct connection through an exclusive power cable to allow the 
electrolyser) to count all its power as renewable; and   
the circumstances under which gases can count as being renewable. There are 
some doubts as to whether the renewable property of gases can only be claimed 
when used outside of transport since Article 27 refers to transport only. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.1.10 

ABSENCE  OF  A  HARMONIZED  DEFINITION  OF  SUSTAINABLE 

INVESTMENT AND THE ROLE OF SECTOR COUPLING THEREIN 

There is a lack of a harmonized understanding of what sustainable investments are. This 
may  hinder  the  flow  of  capital  to  projects  that  serve  decarbonisation  objectives.  A 
classification  system  for  sustainable  investments  is  currently  being  built  by  the  EU 
institutions and a dedicated technical expert group. Sector coupling technologies should 
be considered and appropriately reflected in the classification system for their benefits 
to climate change mitigation and to environmental objectives. For conceptual certainty, 
EU-level,  national  and  corporate  policies  should  also  clarify  the  relevance  of  sector 
coupling  –  one  publicly  accessible  effort  is  the  revision  of  the  EIB’s  energy  lending 
criteria23, which already features references to sector coupling. As noted above, there 
should  be  clarity  on  the  relevant  technologies  and  the  statement  of  their  benefits  to 
decarbonisation. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.2  UNLEVEL PLAYING FIELD DUE TO SECTOR- AND TECHNOLOGY-SPECIFIC TARIFFS 

AND LEVIES 

The  second  group  of  barriers  and  gaps  encompasses  issues  arising  from  technology- 
and  sector-specific  regulation  that  may  become  less  fit-for-purpose  in  the  emerging 
sector-coupled energy market.  

Barriers  in  this  category  are  expected  to  persist  in  the  steady  state  even  after 
transitional issues have been resolved. However, the anticipation of the barriers in the 
steady state may be a barrier for market players to implement the transition.  

23  https://www.eib.org/en/about/partners/cso/consultations/item/public-consultation-
on-eibs-energy-lending-policy.htm 

Page 56 

 
 
  
                                           
 
 
Figure 28 gives  an overview  of the  barriers identified in this  category, as  well as  the 
potential solutions assessed for the short-listed barriers. 

Figure 28 
for short list barriers 

Overview of short and long list barriers in category 2 and the solutions assessed 

Source: Frontier Economics 
Note: Barriers outlined light red belong to the transition, barriers outlined red are steady state 
barriers. 

Steady state 

5.2.1  POWER-TO-GAS FACING END-USER TAXES ON ELECTRICITY 

At present, taxes and levies, i.e. non-generation and non-grid components, constitute 
2/3 of the average EU retail electricity bill.24  

Electricity costs are the main cost driver for power-to-methane, amounting to almost 
40%  for  synthetic  methane  (see  Figure  29).  The  share  is  even  higher  for  synthetic 
hydrogen as power is here the only cost-relevant ingredient. 

Figure 29 Electricity is the main cost driver for power-
to-methane 

24  Cf. Eurelectric (2017). 

Page 57 

 
 
 
 
                                           
 
 
Where current regulations dictate that 
power-to-gas  facilities  are  treated  as 
end  consumers,  electricity  costs 
include  end-user  taxes  and  levies, 
further increasing costs for power-to-
gas facilities (this is the case in many 
countries  for  instance  Germany,  the 
Netherlands and Spain).  

taxes),  but 

Source: Agora and Frontier Economics (2018)25 

A  concern  arises  where  these  taxes 
and levies are not ‘cost-reflective’ and 
intended to drive a specific behaviour 
(as  is  the  case,  for  example,  with 
instead  are 
carbon 
intended  to  recover  costs,  such  as 
those of supporting RES. As with any cost-recovery charges, there is a risk that taxes 
and  levies  distort  the  efficiency  of  the  system.  In  addition,  there  is  a  risk  that  the 
recovery  of  taxes  and  levies  from  power-to-gas  curbs  investment,  and  therefore 
precludes the system from benefiting from this technology (e.g. via reduced electricity 
network expansion requirements, or reduced curtailment of RES). In particular, there is 
a  risk  of  distortion  of  the  level  playing  field  between  synthetic  gases26  and  other 
renewable  gases  as  biomethane,  as  the  latter’s  input  costs  are  not  significantly 
increased by end-consumer taxes and levies.  

This barrier has been retained in the short list of issues and potential solutions are 
therefore assessed below. 

Recommendation  for  power-to-gas  facing  end-user  taxes  on 
electricity 

A solution to this barrier would be to ensure that only final energy consumption in 
electricity  faces  taxes  and  levies.  Energy  storage  or  power-to-gas  facilities  would 
therefore not face taxes and levies on electricity inputs.  

This would be expected to help to reduce the costs of decarbonisation, by ensuring that 
renewable  and  low-carbon  gas  production  technology  choices  are  driven  by  the 
underlying costs to society (as opposed to being distorted by cost recovery taxes and 
levies). This will become even more relevant as any financial support for renewable and 
low-carbon gases is phased out.  However, in the short run, (final) electricity consumers 
might  pay  more  if  levies  previously  paid  by  existing  power-to-gas  facilities  are 
redistributed. 

We note that another potential solution, suggested by some stakeholders, would be to 
remove all taxes and levies (those that are not intended to be ‘cost-reflective’, such as 
carbon  taxes,  but  instead  are  intended  to  recover  costs,  such  as  those  of  supporting 
RES) from energy consumption. The burden of such taxes and levies could instead be 
shifted  to  general  taxation.  In  theory,  using  the  full  flexibility  of  the  tax  system  to 
recover policy-related costs could lead to the least distortive outcome from an economy-

25 All cost shares (in %) and absolute figures (ct/kWh) are rounded and associated with 
the following scenario: North and Baltic Sea, reference scenario 2030, Wind-offshore, 
CO2 from DAC, 6% weighted average cost of capital, no taxes and levies. 
26  Similar  arguments  may  apply  to  hydrogen  produced  by  methane  reforming  (in 
combination with CCS). 

Page 58 

38%31%2%12%17%RES-EPtH2H2 storageCO2H2tCH4Transport 
 
 
                                           
 
 
 
wide  perspective.  However,  given  that  the  sums  involved  would  be  significant,  it  is 
uncertain in practice whether taxing energy use could be avoided completely.  

Figure 30 below summarises our assessment of the option set out above. In summary, 
we would recommend more detailed assessment and policy design work into ways of 
ensuring that only final electricity consumption faces (cost-recovery) taxes and levies. 

Figure  30  Assessment  of  potential  solution  to  address  power-to-gas  facing  end-user  taxes  on 
electricity 

Source: Frontier Economics 

5.2.2  SUNK COSTS AND DISMANTLING COSTS OF GAS INFRASTRUCTURE WEIGHING 

ON GAS GRID FEES  

As the initial analysis (see section 3.3) showed, total final energy demand is expected 
to reduce significantly through energy efficiency measures. Fossil fuels will phase out 
with an uncertain, minor role of natural gas. Since natural gas demand is expected to 
decrease, the (average) utilisation level of the transmission grid, LNG import terminals 
and import pipelines is also likely to decline. This decline may be partly mitigated by the 
extent to which infrastructure can be converted to using increasing shares of renewable 
or low-carbon gases.   

Against this background there are two main risks: 

  First, the risk, on a forward-looking basis, of (inefficient) over-investment (or of 

keeping existing infrastructure online longer than would be efficient).  

  Second,  the  risk  that,  with  declining  volumes  of  gas  transported,  unit  tariffs 
would  need  to  increase  to  ensure  recovery  of  sunk  costs  (i.e.  those  costs 
associated  with  legacy  investments  that  have  been  irreversibly  incurred  and 
which do not vary with consumption).   

The second risk above might in the medium and long term undermine the affordability 
and competitiveness of gas. It may incentivise switching away from gas to other energy 
carriers,  to  an  extent  that  might  not  be  cost  effective  from  a  societal  perspective 
(because the increase in tariffs would not be cost reflective).   

Additionally,  the  geographical  distribution  of  low-carbon  and  renewable  gases 
production may differ from that of natural gas, leading to high dismantling costs in the 
future.  These  costs  may  be  socialised  via  infrastructure  tariffs,  conditional  on  the 
relevant  NRA  allowing  them  as  part  of  the  operator’s  recoverable  cost  base  (e.g. 
assuming that the NRA finds these costs to correspond to those of an efficient operator). 
As such, dismantling costs will be borne by low-carbon and renewable gases consumers 
because  of  the  common  energy  carrier,  and  even  though  the  infrastructure  being 
dismantled was not built for them. The corresponding increase in tariffs would not be 
cost-reflective.   

We  note  that  this  can  be  a  very  relevant  situation  in  the  context  of  power-to-gas 
investment. The case for a continued role of the gas sector in a decarbonising economy 
stems  in  large  part  from  the  ability  to  re-use  existing  gas  infrastructure.  However, 
private investors may only engage in related activity if they face  just the incremental 

Page 59 

 
 
 
 
 
cost of their infrastructure usage. If they are burdened with extensive legacy cost of an 
otherwise  underutilised  gas  infrastructure,  they  may  not  engage  in  new  and  efficient 
investments in the first place. 

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendation  for  sunk  costs  and  dismantling  costs  of  gas 
infrastructure weighing on gas grid fees 

To the extent the issue is related to the risk of prospective over-investment, it may be 
desirable to introduce measures that allow for  more frequent (regulatory) review 
of necessary investments in gas infrastructure in light of demand and production 
uncertainty. This could take the form of a reduced duration of price control periods or 
uncertainty / re-opener mechanisms. Such measures are likely to be a ‘limited regret’ 
way of reducing costs of prospective investments), by reducing the risk of unnecessary 
investments being carried out in the first place. 

One  question  is  whether  network  operators  might  be  well-placed  to  bear  the  costs 
themselves,  in  which  case  a  solution  may  be  to  leave  asset  stranded  risk  with 
network operators. In principle, network operators bearing this risk could lead to them 
being  more  cautious  regarding  prospective  investments,  thereby  avoiding  making 
investments that could be potentially stranded  in the future (i.e. avoiding a potential 
“moral hazard” problem). Alternatively, they might be more innovative  regarding the 
potential for repurposing infrastructure for a different, more profitable, use. This would 
only be an appropriate solution, however, for forward-looking investments over which 
network  operators  are  able  to  exercise  a  degree  of  discretion  (that  is,  investments 
undertaken on their own initiative), as only in such cases would the network operator 
be well-placed to manage such risks. That said: 

 

In practice, a share of investment is likely to be mandated (e.g. out of conformity 
with ongoing security requirements). Identifying the extent to which investments 
are discretionary is not a straightforward exercise. 

  Network operators are likely to require a higher rate of return if they are required 
to bear asset stranding risk than is currently the case in the current regulatory 
framework. This may feed through to higher tariffs, offsetting some of the cost 
savings from more cautious investment decisions. 

Leaving  asset  stranded  risk  entirely  with  network  operators  would  therefore  not  be 
expected to be appropriate for the majority of costs. Some share of investment may be 
viewed  as  mandatory,  and  another  part  may  have  been  agreed  jointly  with  the 
regulator. For past investments, it would be difficult to identify retrospectively the extent 
to which this was driven by regulators or public policy goals (such as security of supply), 
as opposed to by network operators themselves. This is likely to be highly  subjective 
and  depend  on  local  circumstances.  Depending  on  the  implicit  or  explicit  regulatory 
contract, placing stranding risk for existing investment on network operators today may 
constitute a breach of this contract. This has the potential to undermine the investment 
environment in infrastructure going forward more generally, increasing risk and, in turn, 
costs of developing new infrastructure.  

Other solutions are therefore needed to address the distribution of costs associated with 
legacy investment (which cannot be reversed) and whatever future investment is still 
deemed necessary despite the possibility of more frequent regulatory reviews (such as 
investment  required  to  ensure  infrastructure  that  remains  used  meets  security 
standards). As explained above, by construction the recovery of these sunk costs will 
not  be  reflective  of  forward-looking  costs  incurred  on  the  system.  Therefore,  cost-
recovery  solutions  need  to  be  designed  to  mitigate  the  risk  of  distorting  decisions  to 
invest  in  technologies  (at  producer  or  consumer  level)  relative  to  the  decisions  that 

Page 60 

 
 
 
 
would have been made based on purely cost-relfective tariffs. In other words, solutions 
are needed to mitigate the risk that increasing unit tariffs for gases lead to inefficient 
switching away from gas to other energy carriers.  

In order to distribute costs away from gas infrastructure users and gas consumers, the 
State could instead guarantee to cover sunk costs, dismantling costs or both, 
or a taxpayer fund could be set up to cover such costs. This approach may in certain 
circumstances lead to the most efficient outcome from society’s perspective. This would 
be the case if it helps minimise distortions in investor or consumer choices (in particular 
those between different energy carriers) and the resulting welfare losses. Using the full 
flexibility of the tax system also potentially allows for better management of potential 
equity concerns (though at the risk of reducing efficiency).   

However, we appreciate that taxpayer funding may not be an acceptable option in all 
Member States. All (or some) costs may still need to be recovered from infrastructure 
users and energy consumers. To the extent this is the case,  allowing flexibility for 
gas  sunk  or  dismantling  costs  to  be  spread  across  users  of  other  energy 
carriers (such as electricity or heat) could still lead to net benefits to society through 
avoiding  excessively  disincentivising  gas  use  compared  to  other  energy  carriers. 
However,  realising benefits relies on being able to spread costs without creating new 
distortions (or worsening existing ones) between energy carriers. In practice, this may 
be difficult to achieve. 

Measures that allow for increased recovery of costs today (vs tomorrow), such 
as accelerated regulatory depreciation or classifying more spend as OPEX (as opposed 
to CAPEX) may also be a part of the regulatory toolkit.  Their use could help to ensure 
a closer match between the expected pattern of use of gas infrastructure over time and 
the recovery of costs by network operators.  They may also be positive for investment 
(by  increasing  certainty  of  cost  recovery).  However,  given  they  entail  simply  a 
redistribution of costs from future to present consumers, the benefit in terms of avoiding 
distortions to choices between energy carriers is unclear. There is a risk that, taken too 
far,  redistribution  could  result  in  (current)  gas  consumption  being  inefficiently 
discouraged.  To  mitigate  this  risk  therefore,  careful  assessment  of  the  room  for 
redistribution is likely to be needed.  It may be helpful to combine such measures with 
others that seek to shift the burden of sunk cost recovery away from gas consumers to 
other sources (such as those discussed above).  

Figure 31 below summarises our assessment of the options set out above. In 
summary, we would recommend taking forward the following solutions (for more 
detailed assessment and policy design work): 

  more  frequent  (regulatory)  reviews  of  whether  prospective  investments  are 

 

necessary; 
leaving  asset  stranded  risk  with  network  operators  (for  forward-looking 
investments over which network operators exercise a degree of discretion); 
  distributing sunk infrastructure costs away from infrastructure users and towards 

 

taxpayers instead; 
if  redistributing  to  taxpayers  is  not  feasible  (or  not  acceptable),  ensuring  an 
equitable distribution of sunk costs between different energy carriers; and 

  allowing for faster recovery of infrastructure expenditure. 

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Figure 31 Assessment of potential solutions to address sunk costs and dismantling costs of gas 
infrastructure weighing on gas grid fees 

Source: See Appendix C for further detail on the assessment. 

5.2.3  SOME FORMS OF CCS (NON-PIPELINE CO2 TRANSPORT) LIABLE UNDER ETS 

CO2 emissions that are captured and permanently stored do not, under Article 12 of the 
ETS Directive, result in a liability to surrender allowances, for facilities holding a permit 
under Directive 2009/31/EC (on geological storage of carbon dioxide)27. However, some 
stakeholders are concerned that stored GHG emissions might still be liable if transported 
to geological storage via means other than pipeline infrastructure. The basis for such a 
concern  is  unclear,  but  may  stem  from  the  definition  of  ‘transport  network’  under 
Directive 2009/31/EC, which refers only to pipelines. If the concern were valid, it would 
result in a distortion between different types of transport infrastructure for CO2. It might 
hinder applications of CCS (such as production of low-carbon hydrogen), in particular in 
circumstances  where  pipeline  transport  of  GHG  emissions  is  not  feasible  or  cost-
effective.28  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.2.4  CONVENTIONAL HYDROGEN PRODUCTION ON THE CARBON LEAKAGE LIST 

Some sectors are exposed to a significant risk that the costs related to climate policies 
such as the EU ETS make them decide to transfer their business to another country with 
no (or less stringent) constraints on greenhouse gas emissions. This could lead to an 
increase in total global emissions and is therefore referred to as carbon leakage29. As a 

27 OJ L 140, 5.6.2009, p. 114–135.  
28 That said, this barrier may be less relevant to CCS technologies that result in carbon 
in solid form as a by-product. 
29 Cf. https://ec.europa.eu/clima/sites/clima/files/factsheet_ets_en.pdf  

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response to the risk of carbon leakage, certain sectors receive freely-allocated EU ETS 
allowances,  to  safeguard  their  competitiveness  and  thereby  prevent  carbon  leakage. 
The manufacture of industrial gases (which includes hydrogen production) is on the list 
of eligible sectors30.  

The amount of freely-allocated allowances is calculated based on the direct emissions 
associated with hydrogen production. This means that hydrogen produced from steam 
methane reforming (without CCS), for example, would be granted free allowances due 
to  the  direct  emissons  in  the  production  process.  However,  any  production  process 
without direct emissions – such as hydrogen produced from electrolysis – would not31. 
This reduces incentives to switch to alternative, potentially lower emission, production 
methods32.  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.2.5  DISTORTED COMPETITION FOR INPUTS 

There are three examples for distorted competition for inputs: 

Subsidies  or  legal  restrictions  attached to specific  end  usage can be a barrier. 
This may hinder the efficient use of these inputs such as biomass or biogas. If subsidies 
only apply to specific uses they may steer the  system away from using inputs where 
they  are  most  valuable.  For  instance  a  given  gas  could  be  eligible  for  Feed-in-Tariffs 
when  used  for  electricity  generation  but  not  when  used  in  industry  processes33.    If  a 
renewable or low-carbon gas is not used where it is most valuable to the energy system 
as a whole, this is a barrier to its most efficient use and risks increasing total costs.  

Another  example  of  distorted  competition  arises  if  energy  production  inputs  are 
burdened  with  different  taxes.  The  input with lower  taxes  will  have  a  (potentially 
unjustified)  advantage.  In  the  case  of  electricity  production  from  gas,  electricity 
producers  would  prefer  the  lower  taxed  gas  to  save  costs.  For  instance,  in  Italy  only 
biogas  is  exempted  from  taxes  for  electricity  and  heat  self-production  but  not 
biomethane. 

Competition  for  inputs  is  also  distorted  if  CO2-heavy  inputs  are  favoured:  In  the 
context  of  the  energy  transition  it  is  essential  that  there  is  a  market  for  renewable 
characteristics  of  inputs  (and  outputs).  This  can  be  threatened  where  energy  policy 

- 

post 

2020 

30 Cf. https://eur-lex.europa.eu/legal-
content/EN/TXT/PDF/?uri=CELEX:32014D0746&from=EN  
31 Cf. Guidance Document n°9 on the harmonised free allocation methodology for the 
EU-ETS 
f. 
https://ec.europa.eu/clima/sites/clima/files/ets/allowances/docs/p4_gd9_sector_speci
fic_guidance_en.pdf  
32 The extent of the distortion depends on the degree to which installations receiving 
freely-allocated allowances still bear some costs of purchasing allowances. In principle, 
the  amount  of  free  allocation  is  based  on  a  benchmark  emissions  intensity,  meaning 
that those installations less efficient than the benchmark can expect to still bear some 
costs of purchasing allowances.  

Sector-specific 

guidance 

(2019), 

169 

p. 

33  For  instance,  in  Slovakia,  while  there  are  no  targeted  support  schemes  for  the 
production of hydrogen or e-gases from renewable sources, electricity produced from 
biogas of different origins is eligible for feed-in-tariffs. 

Page 63 

 
 
                                           
 
 
tends  to  treat  renewable  energies  and  fossil  energies  alike  or  even  positively 
discriminate fossil energy carriers. In the Czech Republic for example, coal and coke are 
exempted from taxes when used for electricity production while other fossil (though less 
CO2-heavy) fuels like natural gas are not..  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities.  

5.2.6  DISTORTIONS IN CHOICE FROM TAXES AND OTHER POLICY ACTIONS 

Heterogeneous  taxes  and  subsidies  or  legal  restrictions  may  also  arise  as  a 
barrier to effective decion making for end consumers. They may distort end-consumer 
choice  by  shifting  the  preferences  away  from  the  most  effective  and  cost-efficient 
deployment  of  a  given  renewable  or  low-carbon  gas.When  sector  policy  reduces  the 
costs of an energy carrier it leads to two types of distortions.  

  Firstly,  it  hinders  the  level  playing  field  between  energy  carriers  within  a 
specific  sector.  Namely,  tax  adjustments  hinder  the  most  cost-efficient 
(renewable) energy supply of a given sector, because the choice is influenced 
by the different tax burdens rather than  by the true costs. For instance, in 
Greece, there is no distinction between fossil and renewable energy carriers, 
but natural (or synthetic) gas used for transport purposes is untaxed, while 
(fossil or renewable) diesel and petrol have different taxes.  

  Secondly,  this  distorts  the  cost-efficient  usage  of  energy  carriers  and 
therefore  renewable  and  low-carbon  gases  across  sectors.  E.g.  in  France 
renewable gases get a different tax discount if used as a driving fuel than as 
a heating fuel. Similarly, in Spain renewable gases are only on the political 
agenda and receive support in the transport sector. 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities.  

5.3  FOCUS ON NATURAL GAS IN INFRASTRUCTURE REGULATION 

The third and fourth barrier categories relate to infrastructure. Barriers in this section 
are both threats to the take-up of technologies or to a level playing field between them, 
i.e. barriers faced mainly by project developers, and barriers for infrastructure operators 
that  may  hinder  their  ability  to  play  the  role  required  of  them  to  achieve  the  energy 
transition.  

In  the  third  category,  we  focus  on  barriers  that  arise  from  the  fact  that  much  of  the 
regulation and market has been designed with a natural gas focus. As the initial analysis 
has  found,  in  the  future  energy  system,  natural  gas  will  largely  phase  out  by  2050, 
possibly first increasing in the transition. Potentially large-scale use of hydrogen requires 
conversion of existing gas storage or new hydrogen storage locations, and new fuelling 
infrastructure  may  need  to  be  developed  for  the  transport  sector.  Also,  existing  gas 
storages might need to be adjusted to allow more dynamic operation to store renewable 
and low-carbon gases. 

Thus, the barriers in this group arise from the transition of one natural gas to a multitude 
of gas types. Figure 32 gives an overview of the barriers identified in this category, as 
well as the potential solutions assessed for the short-listed barriers. 

Page 64 

 
 
 
Figure 32 
for short list barriers 

Overview of short and long list barriers in category 3 and the solutions assessed 

Source: Frontier Economics 
Note: Barriers outlined light red belong to the transition, barriers outlined red are steady state 
barriers. 

Transition 

5.3.1  UNCERTAIN ACCESS TO INFRASTRUCTURE DUE TO UNCERTAIN OR INADEQUATE 

QUALITY STANDARDS 

Many  technologies  may  only  be  viable  for  developers  if  they  can  be  transported  and 
stored.  Producers  will monetise  the  value  this  creates  at  a  systemic  level  in  the  long 
run. However, for this to be the case, developers need to be confident that they will be 
able to inject into the grid and storage facilities. But quality standards, developed in a 
context where the only gas type was natural gas, currently impose conditions or limits 
and the market is facing uncertainty on the extent to which injection will be possible for 
various types of low-carbon and renewable gas types.  

While norms have been adopted in relation to biomethane in several countries34, we find 
ongoing and widespread uncertainty on the allowed hydrogen blend (for instance in the 
Czech  Republic  and  France).  Sometimes  estimates  exist  but  there  may  still  be 
inconsistencies across sources on the allowed hydrogen share for a given Member State. 
The  compatibility  of  existing  underground  storages  with  hydrogen  is  still  a  topic 

34  And  indeed  EU-wide  standards  also  exist  (EN  16723-1:2016  for  the  injection  of 
biomethane  in  the  natural  gas  grid  and  EN  16723-2:2017  on  natural  gas  and 
biomethane for use in transport).  

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requiring further research in much of the EU.35 The uncertain or inconsistent estimates 
of the allowed hydrogen blend raise the question of whether the restrictions to the blend 
of hydrogen are of a technical or rather regulatory nature. 

Further, uncertainty on the limit for the blend of hydrogen leads to uncertainty on the 
necessary future effort to adjust the infrastructure to be compatible with higher blends 
of hydrogen. 

This barrier has been retained in the short list of issues and potential solutions are 
therefore assessed below.   

Recommendation  for  uncertain  access  to  infrastructure  due  to 
uncertain or inadequate quality standards 

As  discussed  in  section  5.3.1  above,  an  important  first  step  in  addressing  this  are 
consistent quality standards across the EU. Several Member States (such as the UK) are 
reviewing their standards. CEN is working on the inclusion of the Wobbe Index in the H-
gas standard. Resolving issues created by quality differences between Member States 
(see section 5.5.1) will also be important.  

But  even  once  this  has  been  achieved,  further  action  may  still  be  necessary  to  fully 
address the barrier.  

One area for improvement relates to providing improved visibility on gas quality 
for gas producers. The  Interoperability network  code requires  ENTSOG to publish a 
long-term  gas  quality  outlook  and  allows  TSOs  to  provide  information  on  gas  quality 
variation in the shorter term to consumers, DSOs and storage operators. However, it 
does  not  explicitly  require  TSOs  to  do  so,  nor  is  the  provision  of  information  to  gas 
producers mentioned.  

Such information would provide those seeking to inject renewable and low-carbon gases 
into the grid greater clarity on their ability to do so, reducing the uncertainties they face. 
For  example,  if  the  proportion  of  hydrogen  in  the  grid  is  already  at  the  maximum 
acceptable level, there is no scope for additional hydrogen injection to the grid. Knowing 
this could allow investors to pause existing investments, avoiding costs that may later 
prove to be unnecessary.  

Risks  to  developers  are  particularly  likely  to  be  reduced  if  information  provision  is 
implemented  in  conjunction  with  clear  rules  on  how  quality  is  managed  on  an 
ongoing basis. The Gas Directive requires Member States to ensure non-discriminatory 
access for biogas and gas from biomass to the gas system “…provided that such access 
is  compatible  with  the  relevant  technical  rules  and  safety  standards  on  an  ongoing 
basis”.36However, this leaves a number of questions unanswered. Developers may still 
benefit from greater clarity on the rules for managing gas quality and on exactly what 
they might mean for synthetic gases. For example: 

  Ex-ante,  once  limits  are  close  to  being  reached,  should  new  connections  be 
refused (or limited in size) until possible investments to manage quality issues 
can be made? 

  How  can  an  efficient  trade-off  be  struck  between  managing  gas  quality  at 
network level, as opposed to requiring the producer to make improvements to 
quality before injection to the system? 

35 We are aware of assessments of the potential for hydrogen storage in UK salt caverns 
(see ETI, 2018, “Salt Cavern Appraisal for Hydrogen and Gas Storage”), but not of any 
EU-wide assessment of hydrogen storage potential.  
36 Recital 26.  

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 

In  real  time,  what  rules  might  govern  possible  interruption  to  production  to 
ensure  quality  standards  are  met?  What  (if  any)  compensation  should  be 
available if this happens? 

  What  transparency  is  required  regarding  the  rules,  and  what  recourse  should 
developers have in case of disputes with grid operators regarding how rules for 
managing quality have been applied? 

Figure 27 below summarises our assessment of the options set out above. In 
summary, we would recommend taking forward the following solutions (for more 
detailed assessment and policy design work): 

  Providing improved visibility on gas quality for gas producers; and 
  Clear rules on how quality is managed on an ongoing basis. 

Figure 33 Assessment of potential solutions to address uncertain access to infrastructure due to 
uncertain or inadequate quality standards 

Source: See Appendix C for further detail on the assessment. 

5.3.2  LACK OF (INJECTION) CHARGING METHODOLOGY   

Commission  Regulation  (EU)  2017/460  (“NC  TAR”)37  establishes  harmonised 
transmission tariff structures for gas. However, with increasingly decentrally generated 
renewable  and  low-carbon  gases,  the  fundamental  inflow  characteristic  of  the  gas 
infrastructure  may  change,  because  inflow  into  the  gas  infrastructure  may  occur 
anywhere  in  the  transmission  grid  and  in  the  distribution  grid.  In  view  of  this,  some 
gaps may remain in the charging framework: 

  Transmission  grid:  Many  Member  States  do  not  produce  natural  gas 
themselves but import it. This means that gas flows into the national system only 
occurr  via  international  transmission  pipelines  or  LNG  terminals.  With  national 
production  of  low-carbon  and  renewable  gases,  entry  points  and  associated 
tariffs need to be determined for local injection into the different pressure levels 
of the different transmission levels.  

  Distribution grid: Tariffs at the distribution level have historically only covered 
the off-take from the grid and not injection into it, as the inflow came directly 
from  the  higher-pressure  level  transmission  grid.  Currently  the  injection  of 
decentrally produced renewable and low-carbon gases is not part of the charging 
methodology in several Member States.  

The  resulting  uncertainty  on  ongoing  injection  charges  that  may  be  incurred  by  low-
carbon  and  renewable  gas  production  sites  makes  it  difficult  for  potential  technology 
developers and network operators to anticipate future costs. 

37 OJ L 72, 17.3.2017, p. 29–56.  

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This barrier has been retained in the short list of issues and potential solutions are 
therefore assessed below.   

Recommendation for lack of (injection) charging methodology 

As a solution to this barrier, we consider the option of harmonising injection charging 
rules across Member States, particularly covering distribution-injected gases (since 
NC TAR already addresses transmission network entry/exit tariffs for gas). An important 
feature  of  such  rules  would  be  to  avoid  the  creation  of  ‘new’  distortions,  such  as 
(temporary) exemptions from injection tariffs for renewable and low-carbon gases which 
are currently not foreseen under NC TAR.38 

The creation of harmonised rules would increase certainty for developers regarding how 
they might be charged for use of the gas grid, in turn reducing the costs across the EU 
of deploying renewable and low-carbon gases, to the extent it reduces the associated 
risks to developers.   

Harmonisation across Member States could also, in principle, make it more likely that 
deployment of low-carbon and renewable gases happens where it is most cost-effective, 
helping to reduce the costs of their deployment across the EU. However, this depends 
on  the  extent  to  which  resulting  tariffs  are  cost  reflective.  In  addition,  we  note  that 
previous  experience  on  the  network  code  development  process  suggests  that  the 
process to harmonise charging rules could be complex and time-consuming.  

Figure 34 below summarises our assessment of the option set out above. In summary, 
we would recommend harmonised injection charging rules at distribution level (for 
more detailed assessment and policy design work). 

Figure  34  Assessment  of  potential  solution  to  address  the  lack  of  an  (injection)  charging 
methodology 

Source: See Appendix C for further detail on the assessment. 

5.3.3  INCENTIVE  FOR  GRID  OPERATORS  TO  FOCUS  ON  GASES  COMPATIBLE  WITH 

THEIR INFRASTRUCTURE   

The design of the natural gas regulation encourages grid operators to optimise, build 
and maintain transmission infrastructure. This includes a number of incentives that may 
likely  bias  operators  to  facilitate  access  to  the  network  for  those  gases  that  are 
compatible  with  their  current  infrastructure.  This  may  hinder  the  level  playing  field 
between different renewable and low-carbon gases. Biases may arise from:  

  explicit  incentives,  e.g.  financial  incentives  on  uptake  like  connection 
incentives  at  the  distribution  level,  or  booking  or  utilisation  incentives  at  the 
transmission level; and/or 

38 We understand that ACER is of the view that such exemptions may run counter to NC 
TAR. See ACER (2019), “Agency Report: Analysis of the Consultation Document on the 
Gas Transmission Tariff Structure for Belgium”, section 5.2.  

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 

implicit incentives, for instance the fact that declining demand may drive per 
unit  charges  to  consumers  up  and  contribute  to  tougher  negotiations between 
the network operator and the regulator at future price control reviews. 

Additional biases may arise from places other than regulation, such as incentives placed 
on management regarding utilisation of the infrastructure. 

The  degree  to  which  incentives  prevail  will  depend  on  a  wide  range  of  conditions, 
including the framework for granting connections to the grid. In this regard, Directive 
(EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 
on the promotion of the use of energy from renewable sources (“RED II”)39 states: 

"Where  relevant,  Member  States  shall  assess  the  need  to  extend  existing  gas 
network  infrastructure  to  facilitate  the  integration  of  gas  from  renewable 
sources."  

In addition, Directive 2009/73/EC of the European Parliament and of the Council of 13 
July 2009 concerning common rules for the internal market in natural gas and repealing 
Directive 2003/55/EC (the “Gas Directive”)40 states the following:41 

“Member States should take concrete measures to assist the wider use of biogas 
and  gas  from  biomass,  the  producers  of  which  should  be  granted  non-
discriminatory access to the gas system, provided that such access is compatible 
with the relevant technical rules and safety standards on an ongoing basis.” 

The  Gas  Directive  also  requires  NRAs  to  help  achieve  the  “…integration  of  large  and 
small-scale production of gas from renewable energy sources and distributed production 
in both transmission and distribution networks…” and to remove “…barriers that could 
prevent access for new market entrants and of gas from renewable energy sources”. 

Taken  together,  these  provisions  may  provide  some  degree  of  reassurance  for 
developers of renewable gases that Member States will take actions to facilitate  their 
access to the gas system. However, it is not clear how the provisions of the Gas Directive 
would apply to (non-renewable) low-carbon gases and they do not specifically address 
issues related to network operator incentives.  

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendation  for  incentive  for  TSOs  to  focus  on  gases 
compatible with their infrastructure   

Above  we  highlight  a  range  of  examples  of  situations  in  which  network  operators’ 
incentives could result in them focussing on gases that are compatible with their current 
infrastructure  at  the  expense  of  other  gases.  However,  before  arriving  at  concrete 
solutions to address these possible biases, a better understanding of their nature would 
be  needed.  The  first  step  in  addressing  this  barrier  might  therefore  be  a  review  of 
regulatory frameworks to identify such biases in each Member State.  

As also noted above, the framework for granting connections to the grid is likely to be 
one specific factor affecting network owners’ incentives to accommodate renewable and 

39 OJ L 328, 21.12.2018, p. 82–209.  
40 OJ L 211, 14.8.2009, p. 94–136 
41 Recital 26, Gas Directive.  

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low-carbon  gases.  The  current  framework  (RED  II  and  the  Gas  Directive)  may  offer 
some degree of reassurance that access to the gas system will be facilitated.  

Nevertheless, we see room to be more specific that the framework in the Gas Directive 
also applies to (non-renewable) low-carbon gases and that there is an expectation that 
network  operators  will  meet  renewable  and  low-carbon  gas  sources’  requests  for 
connection  to  the  grid.  This  could  be  implemented  via  an  obligation  for  network 
operators to connect renewable and low-carbon gas sources to the gas system, 
provided certain conditions (specified in advance) are met: 

  As is the case currently in the Gas Directive, such an obligation would need to 
be subject to the potential effect on security and safety of operation of the grid, 
including any relevant quality standards (see section 5.3.1 above).   
It might be possible to  require  connections to  be made  even in advance  of all 
required reinforcement works being carried out. But if that is the case, rules to 
manage congestion (at distribution level – see section 5.3.4) become even more 
important.   

 

  The coherence between any connection obligation and the connection charging 
approach adopted (see section 5.1.4) would need to be carefully considered. It 
will probably still be desirable to continue to apply an “economic test” for granting 
new connection requests. 
In cases where low-carbon or renewable gases developers were not satisfied with 
grid  operators’  attempts  to  connect  them  within  a  reasonable  time-frame, 
developers might need to be able to have some form of recourse, for example a 
right of appeal to the NRA.  

 

Due  consideration  would  also  need  to  be  given  to  rules  that  offer  network  owners 
flexibility to justify delay or refusal of a connection under certain circumstances, while 
still ensuring that developers have sufficient trust that their connection request will be 
dealt with efficiently. At the very least, ensuring these conditions are transparent should 
increase  certainty  for  developers.  A  connection  obligation  also  has  the  potential  to 
contribute to speeding up the deployment of renewable and low-carbon gas production, 
leading to a faster realisation of benefits from their deployment.  

Figure 35 below summarises our assessment of the option set out above. In summary, 
as well as a regulatory review to identify possible biases, we would recommend taking 
forward an obligation to connect renewable and low-carbon gas sources for more 
detailed assessment and policy design work. 

Figure  35  Assessment  of  potential  solution  to  address  incentive  for  grid  operators  to  focus  on 
gases compatible with their infrastructure   

Source: See Appendix C for further detail on the assessment. 

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Steady State 

5.3.4  LACK  OF  CLEAR  RULES  /  COMPENSATION  FOR  INTERRUPTION  OF  GAS 

INJECTION 

Renewable and low-carbon gas production is typically capital intensive. High utilisation 
rates  are  therefore  important  for  the  business  case  of  these  technologies  and  their 
competitiveness. Any constraints on utilisation rates imposed by external factors would 
undermine the development of these technologies, thereby constituting a barrier. And 
congestion may be such a constraint.  

Contractual congestion can occur in gas networks when firm capacity bookings exceed 
network  technical  capacity.  It  can  be  managed  through  measures  such  as  over-
subscription and capacity buy-back mechanisms. At transmission level,  guidelines  for 
managing contractual congestion are set out in the Commission Decision of 24 August 
2012 on amending Annex I to Regulation (EC) No 715/2009 of the European Parliament 
and  of  the  Council  on  conditions  for  access  to  the  natural  gas  transmission  networks 
(“CMP Guidelines”).42 

Physical  congestion  can  occur  when  expected  flows  exceed  what  the  network  can 
physically  transport.  This  can  either  be  addressed  by  network  expansion  or 
contractually, via flow commitments. In the gas system, physical congestion is relatively 
rare  in  the  EU  at  transmission  level  today.43  This  is  due  to  the  configuration  of  the 
European gas system with entry from large interconnection points managed via capacity 
bookings. Curtailment of gas has therefore historically not been any issue. 

However,  given  the  expected  role  and  geographical  distribution  of  low-carbon  and 
renewable gases production, congestion may become more frequent, for example during 
the production of: 

  Renewable  gases  from  biomass:  The  high  load  factor,  i.e.  the  constant 
renewable  gas  supply,  may  result  in  congestion  in  summer  in  decentral,  rural 
places  when  demand  for  e.g.  heating  is  very  low.  This  is  particularly the  case 
given that distribution grids have limited linepack flexibility. Increasing the use 
of  compressors,  to  flow  gas  from  distribution  to  transmission  level  (where 
additional  flexibility  sources,  such  as  storage,  may  typically  lie),  may  help 
address seasonal flexibility issues to a large extent. However, it may not always 
be the most efficient solution to deal with all congestion issues.  

  Gases  from  electricity:  Increasing  use  of  intermittent  renewable  electricity 
may  need  to  rely  on  non-intermittent  energy  sources  such  as  gas  to  provide 
system  flexibility.  This  holds  for  excess  supply  of  renewable  electricity  when 
power-to-gas facilities can relieve the electricity system, and for excess demand 
situations where low-carbon and renewable gas fired electricity can supply the 
electricity  system.  However,  this  means  the  intermittency  of  renewable 
electricity sources will be imported to the gas sector, again possibly resulting in 
congestion where gas injections exceed gas demand in a given area. 

42 OJ L 231, 28.8.2012.  
43 EY & REKK (2018), “Quo vadis EU gas market regulatory framework – Study on a Gas 
Market Design for Europe”, Section 4.3.3.  

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Given  the  importance  of  volume  certainty  and  utilisation  (as  described  above), 
developers  of  renewable  and  low-carbon  gases  will  want  to  have  clarity  on  how 
congestion will be managed and how they will be remunerated if they are required to 
reduce or stop injections.  At present, the CMP Guidelines require transmission system 
operators to take the most “cost-effective” measures44 to resolve physical congestion.  
However,  there  are  a  few  examples  from  the  countries  we  reviewed  of  provisions  of 
curtailment  rules  for  unexpected  reductions  in  the  injection  capacity  as  a  result  of 
saturation in the network at the transmission level, and none at distribution level.  

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendations  for  lack  of  clear  rules  /  compensation  for 
interruption of gas injection 

To the extent physical congestion does indeed become more of an issue going forward 
(in  particular  at  distribution  level),  Member  States’  most  likely  response  would  be  to 
implement some rules to address this. We therefore assume some action to address this 
barrier in the counterfactual, whereby developers will eventually get some clarity on the 
congestion management rules that will be in place.  

The  form  those  rules  might  take  is,  however,  uncertain.  For  the  purposes  of  the 
assessment of different options, we assume that, in the counterfactual, Member States 
introduce priority rules governing injection rights at times of network congestion that 
are not necessarily market-based. For instance, in France, gas network operators hold 
a “capacity register” to determine the order in which biogas capacities are injected into 
the network. The allocation works on a “first come, last interrupted” basis, which means 
the producer at the top of the list will have the priority to inject its capacity into the 
network. 

Such  rules  are  not,  however,  the  only  possible  solution.  We  consider  three  solutions 
below, each of which could be applied in different situations.  

Perhaps  the  most  straightforward  solution  to  implement  would  be  interruptibility 
agreements.  By  this  we  refer  to  longer-term  agreements  under  which  participants 
agree to interrupt injection on instruction by the network operator. These could define 
remuneration  in  the  event  of  interruption  and  be  awarded  through  competitive 
tendering. Alternatively, they could form a voluntary part of the connection agreement 
(i.e. the injection facility might in return benefit from a reduction in connection or grid 
use fees).  

  Such  agreements  could  provide  an  efficient  way  of  managing  congestion, 
particularly if awarded  through competitive tendering. Those players  providing 
congestion  management  services  would  be  those  able  to  provide  flexibility  at 
lowest cost.  
If  used  in  conjunction  with  a  system  of  (real-time)  market-based  curtailment 
(see below), agreements could provide clearer long-term signals regarding the 
value of flexibility, making this easier for developers to factor in their investment 
decisions. 

 

  Overall,  investors’  technology  choices  (or  their  choices  regarding  where  to 
invest) are likely to lead to lower costs of addressing network congestion issues 
than is otherwise likely to have been the case. 

44 CMP Guidelines, recital 8.  

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Shorter-term  markets  for  resolving  locational  constraints  could  be  another 
solution. For instance, network operators could set up a system inviting bids to reduce 
injection  for  resolving  locational  constraints.  Such  a  system  could  also  be  open  to 
demand-side  response  and  (where  this  has  the  potential  to  help  address  issues  at 
distribution level) actors connected to the transmission system.  

  As for interruptibility agreements, market-based interruption and compensation 
would  help  to  ensure  that  network  congestion  issues  are  dealt  with  cost-
effectively  and  that  market  participants  are  rewarded  for  their  contribution  to 
addressing congestion. 

  Shorter-term  markets  could  allow  for  greater  efficiency  than  (long-term) 
interruptibility agreements alone, since they would allow players to reflect the 
changes over time in the cost of providing flexibility.  

  However, it may be more complicated to set up (depending on the arrangements 
individual Member States already have in place). Given this, its introduction may 
depend on the severity and nature of the congestion problem.  

Alternatively,  operators  might  be  obliged  (for  example  as  part  of  their  connection 
agreement)  to  interrupt  when  required  by  the  network  operator  (possibly  with 
remuneration  for  doing  so).  Such  interruptibility  obligations  could  be  placed  on 
operators  in  situations  where  there  may  be  a  limited  number  of  options  to  address 
localised  congestion  issues,  leading  to  possible  market  power  concerns.  In  such 
situations,  market-based  congestion  management  may  not  necessarily  result  in  the 
lowest costs to consumers (for example if some players can make excessively high bids, 
compared to their costs, to resolve congestion). Obligations could be used to help cap 
the cost of congestion management. However, to limit the potential for negative investor 
perception, use of such obligations by network operators may need to be subject to NRA 
approval.    

Several  stakeholders  have  called  for  priority  access  for  renewable  (and  low-carbon) 
gases, though it is not clear from submissions exactly to what this refers.  If analogous 
to terminology sometimes used in electricity, it would refer to some kind of guarantee 
regarding producers’ ability to inject gases into the system as they are produced.  Such 
a  guarantee  is  unlikely  to  allow  for  efficient  management  of  congestion.  And  if 
participation in congestion management is voluntary and market-based (i.e. flexibility 
need only be provided at a price nominated by the flexibility provider), it  is not clear 
what value such a guarantee would offer to the producer.  However, should congestion 
management  not  be  market-based,  there  could  be  a  rationale  for  granting  priority 
access  to  renewable  and  low-carbon  gases.    Without  market-based  congestion 
management, it would be difficult for congestion management to be efficient.  From that 
starting point, the risk of a further loss in efficiency (from granting priority access) may 
be seen as a price worth paying to ensure low-carbon and renewable gases producers 
have improved certainty regarding utilisation.  

Figure 36 below summarises our assessment of the options set out above. In 
summary, we would recommend taking forward the following solutions (for more 
detailed assessment and policy design work): 

  Competitively tendered voluntary agreements between network operators 

and participants to limit injections; 

  More sophisticated market-based systems allowing for real-time adjustment 

of bids; 

  Obliging participants to limit injections in situations where there are possible 

market power concerns. 

Page 73 

 
 
 
 
Figure 36 Assessment of potential solutions to address the lack of clear rules / compensation for 
interruption of gas injection 

Source: See Appendix C for further detail on the assessment. 

5.3.5  UNCERTAINTY  ON  THE  REGULATION  OF  HYDROGEN  (&  OTHER  NEW  GASES) 

INFRASTRUCTURE   

While  the  Gas  Directive  sets  out  clear  rules  for  unbundling,  third-party  access  and 
tarification, it is not clear how these provisions might apply to gases other than natural 
gas, biogas and gas from biomass. In particular, it is not clear how EU rules apply to 
(low-carbon  and  renewable)  hydrogen  and  potential  other  new  gases.  Typically, 
infrastructure for such gases are not regulated at the Member State level either.  

Currently, development of hydrogen infrastructure is at relatively small scale. It may be 
possible to deal with any market power abuse issues under competition law. However, 
in  principle,  as  hydrogen  networks  start  to  approach  the  scale  of  current  natural  gas 
networks, regulation in a similar way to existing gas networks may become required to 
ensure producers and consumers benefit from access to required infrastructure in a non-
discriminatory and competitive manner. The question for investors (in long-lived assets) 
is  therefore  what  the  trigger  for  moving  to  regulation  would  be,  and  how  existing 
investment might be dealt with if/when such a move happens. 

  Therefore, there is a high uncertainty on whether hydrogen infrastructure will in 
the future be regulated similarly to natural gas infrastructure. This uncertainty 
may  drive  inefficient  levels  of  investment  in  corresponding  infrastructure,  or 
investment at inefficiently high costs due to increased financing costs in the light 
of  this  uncertainty.  Energy  producers,  merchants  or  industry  companies 
may  be  prepared  to  invest  in  e.g.  hydrogen  pipelines  connecting  a  power-to-
hydrogen  facility  to  an  industry  location.  However,  they  may  abstain  from 
building this pipeline if they are uncertain that the infrastructure will fall under 
TPA  requirements,  or  be  mandated  to  be  transferred  to  a  third-party 
infrastructure operator, with the introduction of the next regulation. 

  Network operators may also view the build-up of infrastructure for renewable 
and low-carbon gases as central to their strategy. However, as long as they are 
uncertain about whether this infrastructure will be part of their RAB, they may 
abstain from this investment. 

  Whether or not infrastructure is regulated may be expected to have an impact 
on the rate of return required from investors to build the infrastructure, with this 
eventually being reflected in costs borne by end users. Costs will be minimised 
if investment is undertaken by those investors requiring the lowest level of return 
for a given level of risk or profile of regulation. The uncertainty around regulation 
may hinder this efficient matching of infrastructure projects with investors.  
  Overall, this may lead to under-investment in hydrogen infrastructure, compared 
to  what  might  be  optimal  from  a  societal  perspective.  It  also  creates  a 
disincentive  for  developing  hydrogen  (compared  to  other  gases  for  which  the 
regulatory framework is clearer).  

Page 74 

 
 
 
 
 
This gap has been retained in the short list of issues and potential solutions are therefore 
assessed below.   

Recommendation  for  uncertainty  on  the  regulation  of  hydrogen 
(& other new gases) infrastructure   

As discussed above, in the absence of further action, the default position at present at 
EU-level  is  that  hydrogen  infrastructure  is  unregulated  and  that  infrastructure  is  not 
required to provide Third Party Access (TPA). The potential solution we consider is to 
clarify whether (and under what conditions) the provisions of the Gas Directive 
apply to hydrogen (and other gases).  Doing so is likely to provide increased clarity 
for  developers  of  renewable  and  low-carbon  gases  regarding  their  ability  to  secure 
access to infrastructure, reducing the risks to investment. That said, agreeing on the 
conditions for regulating hydrogen infrastructure and on the treatment of infrastructure 
build prior to regulating is likely to be a complex process. 

Figure 37 below summarises our assessment of the options set out above. In 
summary, we would recommend further assessment of the conditions under which the 
provisions of the Gas Directive apply to hydrogen (and other gases). 

Figure 37 Assessment of potential solutions to address uncertainty on the regulation of hydrogen 
(& other new gases) infrastructure   

Source: See Appendix C for further detail on the assessment. 

5.3.6  RESTRICTIONS ON TSOS’ ABILITY TO OPERATE INFRASTRUCTURE FOR OTHER 

GASES   

In  some  Member  States  regulation  prohibits  infrastructure  operators  from  owning  or 
operating any infrastructure that is not used to transport natural gas specifically. These 
regulations  have  sometimes  resulted  from  historic  developments  rather  than  from  a 
current  regulatory  need.  For  instance,  in  the  Netherlands,  Gasunie  is  not  allowed  to 
operate hydrogen infrastructure at the moment. This is the case because Gasunie was 
originally founded to exploit the natural gas in Groningen.  

However, as it stands, such a prohibition may risk preventing TSOs from  using gases 
containing  hydrogen  blends  in  their  network.  This  risks  slowing  down  the  pace  of 
decarbonisation of gas.  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.3.7  OVERLY  RIGID  CALORIFIC  VALUE  REQUIREMENTS 

FOR  BILLING 

DISADVANTAGING SOME GASES   

Different  gas  types  contain  different  calorific  values.  This  may  cause  technical  and 
regulatory barriers. 

For  technical  reasons  pipelines  and  appliances  are  sometimes  not  compatible  with 
different gas qualities. In Germany, the Netherlands, France and Belgium, there are two 

Page 75 

 
 
 
 
 
different natural gas qualities, low calorific gas and high calorific gas, which have to be 
transported in separate systems within defined ranges45. However, while it is important 
to adhere to necessary technical and safety standards, overly rigid quality requirements 
may hamper the transport of different types of gases unnecessarily.  

Issues can also arise where, instead of allowing for gases of different calorific value to 
be injected into the same network, a rigid standard is imposed. In the UK for example, 
the billing regime effectively requires lower calorific value gases (such as biomethane) 
to be upgraded (e.g. by adding propane) before injection to the grid. Work is ongoing 
to find solutions that would avoid the need for such pre-processing.   

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.3.8  LONDON PROTOCOL BANS CO2 EXPORTS  

The  “London  Protocol”  is  an  international  agreement  on  the  prevention  of  marine 
pollution. Article 6 of the London Protocol prohibits contracting parties from allowing the 
export of wastes or other matter to other countries for dumping or incineration at sea. 
The article has been interpreted by contracting parties as prohibiting the export of CO2 
from a contracting party for injection into sub-seabed geological formations.46 

This  is  a  barrier  to  cross-border  co-operation  on  offshore  CO2  storage,  which  in  turn 
may be a barrier to the development of CCS technologies.  

An  amendment  was  put  forward  in  2009  by  some  contracting  parties  to  allow  cross-
border transport of CO2 for storage. However, it has yet to be ratified by the required 
two thirds of contracting parties.47 An interim solution could be using Article 25 of the 
Vienna Convention on the Law of Treaties which allows for the provisional application of 
international treaties if the negotiating states agree. 48 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, this issue represents a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

5.4  UNCOUPLED AND UNCOORDINATED INFRASTRUCTURE PLANNING 

This  group  also  encompasses  barriers  related  to  the  infrastructure  required  for  the 
efficient uptake of renewable and low-carbon gases and sector coupling technologies, 
but focuses  on issues  related to silos between infrastructure levels (transmission and 
distribution)  and  sectors  (electricity  and  gas).  These 
issues  arise  because 
decarbonisation of the energy system will result in an increasing level of integration of 

Europe, 

https://www.open-grid-europe.com/cps/rde/oge-

45  Cf.  Open  Grid 
internet/hs.xsl/L-H-Gas-Umstellung-2952.htm?rdeLocaleAttr=en&rdeCOQ=SID-
93DC6E8F-5E23F933  
46 Garrett, J and McCoy, S (2013) ‘Carbon capture and storage and the London Protocol: 
recent efforts to enable transboundary CO2 transfer’, Energy Procedia 37 (2013) 7747 
– 7755. 
47 
london-convention-s-export-amendment-for-ccs 
48 
18232-English.pdf 

https://ieaghg.org/ccs-resources/blog/slow-progress-again-on-ratification-of-the-

https://treaties.un.org/doc/Publication/UNTS/Volume%201155/volume-1155-I-

Page 76 

 
 
                                           
 
 
different energy carriers, in particular gas, electricity and heat. For the purpose of this 
study, we understand sector coupling as linking the EU electricity and gas sectors, both 
in terms of their markets and infrastructure.  

Figure 38 gives  an overview  of the  barriers identified in this  category, as  well as  the 
potential solutions assessed. 

Figure 38 
for short list barriers 

Overview of short and long list barriers in category 4 and the solutions assessed 

Source: Frontier Economics 
Note: Barriers outlined light red belong to the transition, barriers outlined red are steady state 
barriers. 

Steady State 

5.4.1  RISK THAT SUITABLE STORAGE WILL NOT BE AVAILABLE 

Gas storage operators may be uncertain as to what extent there will be requirement for 
gas storage in the future energy system:  

  Firstly,  they  face  demand  risks.  The  findings  from  the  analysis  to  support 
Objectives  1  and  2  signal  the  possibility  of  reduced  gas  demand  in  the  future 
energy system. This may lead to lower demand for gas storage. 

  Secondly, storage operators face technical risks. Existing storage facilities may 
not be suitable for gases such as biomethane (due to high oxygen content) or 
hydrogen  -  either  because  the  gases  are  incompatible  with  the  pipeline 
infrastructure or with the storage facility itself.  

Storage  operators  may  therefore  decide  to  stop  operating  storages.  In  addition  to 
security  of  supply  risks,  which  are  not  the  focus  of  this  report,  this  may  impact  the 
ability in the longer run for the system to benefit from the full value of gases, given part 
of  this  value  resides  in  storability  (in  particular  in  an  energy  system  with  increasing 
volumes  of  intermittent  renewable  sources  and  increasing  flexibility  needs,  including 
need  for  seasonal  storage).  Insufficient  investment/too  much  divestment  in  storages 
thereby  hinders  a  cost-efficient  energy  transition.  In  fact,  currently  there  is  no  clear 
pattern on storage obligation on the Member State level.  

We  note  that  the  manner  in  which  this  barrier  materialises  may  vary  across  Member 
States depending on current regulations in place and adaptations already undertaken. 
For instance, the presence (and level of) storage obligations provides a signal to storage 
operators. However, this signal will only continue to be effective where the regulation is 
adapted to the emergence of low-carbon and renewable gases (that is, that any impact 
of  changes  in  gas  types  on  the  presence  and  level  of  obligation  is  clarified).  Some 

Page 77 

 
 
 
 
 
countries, like the Netherlands, have already adapted regulation in relation to storage 
obligations to low-carbon and renewable gases, but this is not the case across Member 
States where such obligations are currently in place. 

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendation  for  risk  that  suitable  storage  will  not  be 
available 

The first step towards overcoming this barrier would be to assess the implications of 
the expected change in the role of gas as well as the mix of technologies on 
the  likely  optimal  level  of  gas  storage  capacity  (at  EU-level  and  its  regional 
distribution). This would include assessing whether specific types of gas storage capacity 
are needed (for example to store particular gases). While we would envisage a focus on 
storage in gaseous form, any assessment of the optimal level of storage would need to 
take into account other forms of flexibility both in the gas system and elsewhere in the 
energy system, including other forms of energy storage. 

The  direct  costs  and  benefits  of  such  an  assessment  might  be  limited  in  magnitude. 
However, it might be an enabler of possible future action that might deliver benefits to 
society.  Depending  on  the  outcome  of  the  analysis  on  the  optimal  level  of  storage 
capacity referred to above, there may be a need to assess the risks that market and 
regulatory  signals  received  by  storage  operators  could  drive  inefficient  investment  or 
closure decisions. Should this be the case, further intervention may be required, though 
we do not assess the possible options for the time being.  

We  note  there  is  a  risk  that  even  a  limited  intervention  such  as  this  may  create  an 
uncertainty regarding the nature of possible future policy or regulatory intervention on 
storage. We also note this may be an area in which there are benefits to co-ordinated 
action at EU level, for example should there be risks that decisions in one Member State 
may affect the energy system in another Member State.  

Figure 39 below summarises our assessment of the option set out above. In summary, 
we would recommend further work is carried out into a possible assessment of the 
implications of the expected change in the role of gas as well as the mix of 
technologies on the likely optimal level of gas storage capacity. 

Figure  39  Assessment  of  potential  solution  to  address  risk  that  suitable  storage  will  not  be 
available   

Source: See Appendix C for further detail on the assessment. 

5.4.2  INSUFFICIENT  CO-ORDINATION  ON  FUTURE  USE  OF  TRANSMISSION  AND 
DISTRIBUTION  INFRASTRUCTURE:  GEOGRAPHIC  MAPPING  OF  PRODUCTION, 
AND IMPLICATIONS FOR CONNECTIONS AND INFRASTRUCTURE ADAPTATION 

Lack of coordination between transmission and distribution infrastructure operators may 
be a barrier to cost efficiency.  

Gas infrastructure operators are currently competing for connections to renewable and 
low-carbon  gas  production  sites,  but  due  to  different  charging  rules  between  the 
transmission and distribution level, the lowest connection cost signalled to the consumer 

Page 78 

 
 
 
 
may not represent the least cost option for the system. A similar issue may arise in the 
absence of harmonised charging rules across transmission and distribution networks.  

Additionally, a consistent geographical mapping of production sites and of the underlying 
production  potentials  are  important  firstly  to  optimise  the  connection  location  and 
secondly to take into account the resulting required infrastructure adaptations. In the 
long run the optimal design of the gas system will depend on the least cost options to 
facilitate injection and transport  of gases produced  from least cost technologies. This 
may involve significant changes in the infrastructure design, such as enabling reverse 
flows or investment into additional linepack. Optimising the long run design of the gas 
system would require coordination between distribution and transmission level planning. 

We note that, beyond investment, there is value in co-ordinated system operation. This 
may involve sharing of  information on production / flows,  or co-ordinated (real-time) 
system operation. However, we would expect this to be addressed by obligations and 
incentives on operators to ensure system stability. This indeed appears to be the explicit 
intention of Article 13 and Article 25 of the Gas Directive, which require TSOs and DSOs 
respectively  to  share  information  with  other  parties  to  facilitate  “secure  and  efficient 
operation”.  

This regulatory gap has been retained in the short list of issues and potential solutions 
are therefore assessed below.   

Recommendation  for  insufficient  co-ordination  on  future  use  of 
transmission and distribution infrastructure: geographic mapping 
of production, and implications for connections and infrastructure 
adaptation 

We  consider  a  potential  solution  of  mandating  co-ordinated  system  planning 
between  transmission  and  distribution.  Such  planning  would  involve  the 
development of a consistent  geographic mapping of current and projected production 
and demand as a first step. This would allow operators to identify required investments, 
having in mind the feasible options across both levels of the gas network.  Co-ordinated 
planning does not itself guarantee minimising overall costs across the transmission and 
distribution systems of  accommodating renewable and low-carbon gases.  However, it 
may enable this, where network operators have incentives to achieve cost savings.   

Given this, regulatory incentives to achieve system cost savings  may also need 
to  be  part  of  the  solution.  While  network  operators  will  typically  have  incentives  to 
achieve cost savings once price/revenue caps have been set, it may also be worth giving 
thought  to  how  they  can  be  incentivised  to  draw  up  network  plans  that  maximise 
synergies  across  distribution  and  transmission.  Information  asymmetries  can  make  it 
challenging in practice for regulators to implement such incentives.  

In  some  Member  States  (such  as  Denmark),  the  same  company  owns  both  gas 
transmission  and  distribution  grids.  This  is  clearly  another  way  of  ensuring  co-
ordination. However, we do not consider it further as it may not be reasonable to assume 
that  adopting  this  model  would  be  politically  acceptable  in  other  Member  States.  In 
addition, while joint ownership might facilitate co-ordination, it does not guarantee it, 
nor  does  it  ensure  that  co-ordination  leads  to  optimisation  of  costs  from  a  system 
perspective.49 

49 Although in Denmark’s case there is an obligation on network operators to use social 
CBA analysis which may contribute to this objective.  

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Figure 40 below summarises our assessment of the options set out above. In 
summary, we would recommend taking forward the following solutions (for more 
detailed assessment and policy design work): 

  Co-ordinated  infrastructure  planning  between  transmission  and  distribution 

networks; and 

  Regulatory incentives on individual operators to achieve cost savings at system 

level 

Figure 40 Assessment of potential solution to address insufficient co-ordination on future use of 
transmission and distribution infrastructure  

Source: See Appendix C for further detail on the assessment. 

5.4.3  INSUFFICIENT  CO-ORDINATION  ON  FUTURE  USE  OF  ELECTRICITY  AND  GAS 

TRANSMISSION INFRASTRUCTURE – AND ALIGNED OPERATOR INCENTIVES 

Another  current  barrier  may  arise  from  the  separate  development  of  systems  for 
electricity and gases. Integrated network planning of electricity and gas networks (both 
on the transmission or distribution levels) is essential to prevent inefficient bias towards 
single  network  types.50  The  long  run  optimal  design  of  the  network  is  driven  by 
interactions between electricity and gases, such that the least cost infrastructure may 
only  be  designed  and  built if it is  planned  jointly  by  electricity  and  gas  infrastructure 
operators. Not only could coordination enable the optimisation of the mutual investment 
programmes but also the realisation of possible operational gains51.  

ENTSOG  and  ENTSO-E  have  already  taken  the  first  steps  in  co-ordinating  their 
respective  Ten  Year  Network  Development  Plans  (TYNDP).  For  the  TYNDP  2018, 
ENTSOG  and  ENTSO-E  developed  joint  scenarios  intended  to  capture  relevant 
interlinkages  between  the  electricity  and  gas  sectors.  As  part  of  this  process,  the 
ENTSOs  are  also  developing  an  interlinked  electricity  and  gas  model.  This  model  will 
eventually be used to support the cost-benefit analysis of projects for which electricity 
and gas interlinkages are deemed to be particularly relevant.52 However, there may also 
be further benefits to be realised in ensuring greater co-ordination between electricity 
and gas TSOs (and DSOs) at national level.  

We note that, beyond investment, there is value in co-ordinated system operation. This 
may involve sharing of  information on production / flows,  or co-ordinated (real-time) 
system  operation.  Provided  that  electricity  and  gas  system  operators  can  base  their 
decisions on independently observable market conditions, such as the relative price of 
different heating options, there may be no need for explicit new provisions. However, 

50  A  specific  local  example  is  in  Italy.  When  new  isolated  areas  such  as  Sardinia  are 
connected to energy supply, currently there is no assessment on which energy carrier 
besides natural gas (whether it is electricity, hydrogen, heat etc.) are suitable options. 
51 Cf. Trinomics (2018), The role of Trans-European gas infrastructure in the light of the 
2050 decarbonisation targets 
52 ENTSO-E and ENTSOG joint presentation titled “Focus Study Interlinked Model 
Joint ENTSOs Workshop”, dated 17 May 2018.  

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where more complex flows or higher loads on either network imply the need for one or 
another system operator to take additional unobserved network actions that impact the 
other operator, it may be necessary to revisit whether scope for greater collaboration is 
desirable. Existing EU regulations do not explicitly require gas and electricity TSOs and 
DSOs to share information across sectors.   

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendation  for  insufficient  co-ordination  on  future  use  of 
electricity  and  gas  transmission  infrastructure  –  and  aligned 
operator incentives 

Our  focus  is  on  the  planning-related  aspects  of  the  barrier.  Similarly  to  above,  we 
consider  a  potential  solution  of  mandating  co-ordinated  system  planning  across 
electricity and gas transmission (and potentially also at distribution level). First 
steps  have  already  been  taken  in  this  direction,  such  as  the  joint  scenario  planning 
exercise  carried  out  by  the  ENTSOs  and  the  development  of  an  interlinked  gas  and 
electricity model (described above). Similar co-ordination at national level (whether at 
TSO  or  DSO  level)  would  also  be  beneficial.  This  would  allow  operators  to  identify 
required  investments,  having  in  mind  the  feasible  options  across  electricity  and  gas 
networks and would be an important enabler for achieving cost savings.  

Regulatory incentives to achieve system cost savings may also need to be part of 
the  solution.  While  network  operators  will  typically  have  incentives  to  achieve  cost 
savings once price/revenue caps have been set, it may also be worth giving thought to 
how  they  can  be  incentivised  to  opt  for  investments  that  maximise  synergies  across 
electricity  and  gas.  Information  asymmetries  can  make  it  challenging  in  practice  for 
regulators to implement such incentives.  

As  above,  while  we  note  that  common  ownership  of  electricity  and  gas  transmission 
networks is a feature in some Member States, and could theoretically aid co-ordination, 
it would not in itself ensure cost savings, and we assume that it would not be easily to 
apply more widely across Member States.  

Figure 41 below summarises our assessment of the option set out above. In summary, 
we would recommend taking forward the following solutions (for more detailed 
assessment and policy design work): 

  Co-ordinated  infrastructure  planning  between  electricity  and  gas  network 

operators; and 

  Regulatory incentives on individual operators to achieve cost savings at system 

level 

Figure 41 Assessment of potential solution to address insufficient co-ordination on future use of 
electricity and gas transmission infrastructure  

Source: See Appendix C for further detail on the assessment. 

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5.5 

 RISK FOR INTEROPERABILITY ACROSS MARKETS AND BORDERS 

Group  five  comprises  barriers  relating  specifically  to  the  interoperability  between 
different markets. Figure 42 gives an overview of the barriers identified in this category, 
as well as the potential solutions assessed for the short-listed barriers. 

Figure 42 
for short list barriers 

Overview of short and long list barriers in category 5 and the solutions assessed 

Source: Frontier Economics 
Note: Barriers outlined light red belong to the transition, barriers outlined red are steady state 
barriers. 

Transition 

5.5.1  POSSIBLE LACK OF INTRA-EU CO-ORDINATION ON STANDARDS  

There are numerous examples of gas standards being different across Member States.53 
For  instance,  there  are  differences  between  oxygen  limits  between  Denmark  and 
Northern  Germany.  These  may,  in  the  near  future,  result  in  barriers  to  cross-border 
trade  in  gases.54  Other  Member  States  may  face  similar  issues  as  biomethane  and 
hydrogen injection increases in the future.  

53 Cf. 6th CEER benchmarking report on the quality of electricity and gas supply (2016).  
54  There  is  a  0.5%  (molar)  limit  on  oxygen  in  biomethane  in  Denmark.  In  Germany, 
different oxygen limits can be applied by different gas system operators, depending on 
the vulnerability of the specific facilities located in each network. Gasunie Deutschland 
allows only 10ppm (molar) oxygen to flow from Denmark, given (we understand from 
Energinet) the vulnerability of storage facilities located on its network.  

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There may be sound technical justifications for Member States adopting different gas 
quality  standards.  For  example,  domestic  gas  infrastructure  may  only  be  compatible 
with a specific gas quality.  

The concern here is therefore not necessarily the lack of harmonisation. Rather, it is the 
lack of co-ordination between Member States and neighbouring TSOs, and whether this 
could end up being a barrier to physical trade. 

In  particular,  we  see  potential  risks  to  cross-border  trade  where  Member  States  are 
insufficiently flexible in their application of gas quality standards. For example, Member 
States may apply stringent quality standards at the level of the whole grid when only 
certain  installations  are  vulnerable.  This  may  prevent  imported  and  domestically 
produced  gases  from  flowing  in  the  parts  of  the  network  that  are  less  vulnerable. 
Alternatively,  Member  States  (or  neighbouring  TSOs)  may  fail  to  co-ordinate  on  the 
investments  required  to  manage  potential  quality  issues  (for  example  on  oxygen 
removal). 

In  principle,  this  co-ordination  barrier  is  already  addressed  under  Commission 
Regulation  (EU)  2015/703  of  30  April  2015  establishing  a  network  code  on 
interoperability and data exchange rules (the ‘Interoperability network code’)55. Under 
Article 15 of the Interoperability network code: 

  TSOs are required to co-operate to avoid restrictions to cross-border trade due 

to gas quality differences; 

  NRAs may require TSOs to co-operate to develop options, to perform a CBA on 
the  assumptions  and  submit  a  joint  proposal  for  removing  the  restriction  and 
submit this for NRA approval 

  NRAs are required to consult NRAs of other Member States concerned and take 

account of their opinion (ideally reaching agreement).  

Given this this barrier is already addressed in principle by existing legislation, it has not 
been  retained  in  the  short  list  of  issues  as  part  of  this  study.  However,  these  issues 
represent a  risk for the achievement  of the  energy transition and would benefit from 
further investigation and potential intervention by relevant authorities. 

5.5.2  ACCESS TO HUB TRADING FOR GASES INJECTED AT DISTRIBUTION LEVEL 

The European gas market is designed on the concept of ‘hub’ trading, with entry and 
exit points typically defined at interconnection points, storage facilities, LNG terminals 
and domestic exit points.   

Energinet has informed us that currently they are able to design and operate the Danish 
transmission  system  such  that  only  gas  with  less  than  10ppm  oxygen  is  flowing 
southbound  on  the  Ellund  border  to  Germany.  When  the  Tyra  field  is  shut  down  for 
maintenance 2019-22, no southbound flows are expected at all. From 2022, once Tyra 
is expected to be up and running again, an enduring solution would need to be in place 
to ensure gas can be exported from Denmark to Germany. 
Energinet  has  therefore  started  a  so-called  ‘Oxygen  Task  Force’  considering  potential 
solutions,  such  as  removing  the  oxygen  directly  at  the  production  site,  at  the  border 
point  or  at  the  connection  point  for  the  vulnerable  assets  etc.  It  is  also  developing  a 
long-term  view  of  how  oxygen  limits  at  European  level  can  be  set  while  minimising 
barriers to the growth of biomethane production. 
55 OJ L 113, 1.5.2015, p. 13–26.  

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Historically, there has been limited gas production at distribution level, though this is 
changing with biomethane injection typically taking place at distribution level. Injection 
from power-to-gas facilities might also take place at distribution level.  

To allow distribution-connected gases to be traded in the same way as other supplies, 
there is therefore a need to define an entry point to the ‘hub’ for them. Member States 
with biomethane injection (such as Italy and Denmark) have already done this. 

Generally, we expect other Member States to take similar steps, if and when injection 
to local gas grids starts becoming a reality. However, we have still noted the issue in 
this  study,  as  it  would  require  a  conscious  decision  from  Member  States  to  facilitate 
trade  of  local  gas  production,  potentially  also  requiring  updates  to  metering 
arrangements.  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

Steady State 

5.5.3  RISK OF LACK OF LIQUID MARKET FOR SALE OF HETEROGENOUS GASES 

The competitiveness of natural gas today stems, among other, from the level of liquidity 
achieved in the internal market (albeit with ongoing differences across Member States). 
Given  the  heterogeneity  in  technologies  that  may  be  deployed  to  achieve  the 
decarbonisation  of  the  energy  sector,  which  may  vary  by  regions,  there  is  a  risk  of 
fragmentation of the gas market into different  products and different  regions.  This is 
less likely to be an issue where gases are blended together, since it should be possible 
to  simply  ensure  trade  in  units  of  energy  (subject  to  overcoming  issues  related  to 
calorific value requirements – see section 5.3.7). However, it may be an issue to the 
extent  that  there  is  significant  growth  in infrastructure  dedicated  for  particular  gases 
(for example, for hydrogen).   

This results in the risk that liquidity could fall, increasing costs and risks for gas market 
participants,  and  potentially  also  deterring  investment.  Future  developments  might 
partially mitigate this risk.  

  Growing numbers of physical interconnections between hydrogen and methane 
supply chains (see section 3.3.3) will enhance price linkages between fuels. This 
could  ultimately  allow  market  participants  to  hedge  price  risks  in  one  fuel  by 
trading in another.  

  Widening the EU market for gases through promoting interconnections or market 

reforms will help to reduce fragmentation further. 

  The development of new gas sources could result in new players coming to the 
market with more diverse trading needs. For example, to the extent that power-
to-gas  production  operates  flexibly  depending  on  electricity  prices,  this  might 
drive greater short-term trading in gas markets.   

However, it is difficult to predict with certainty the impacts such developments might 
have on liquidity. As a result, market participants may perceive a risk that liquidity could 
fall.    This  perception  itself  may  increase  the  cost  of  investments  in  low-carbon  and 
renewable  gases.  If  levels  of  liquidity  were  to  eventually  fall,  this  would  (in  addition) 
result in an increase in the costs to market players associated with risk management.   

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Page 84 

 
 
 
 
Recommendation  for  risk  of  lack  of  liquid  market  for  sale  of 
heterogenous gases 

While it may not be possible to entirely remove any risk market participants perceive 
regarding  a  possible  fall in  liquidity,  some  steps  may  help  to  both  limit  any  eventual 
decline in liquidity.  

One  potential  solution  we  consider  is  a  more  systematic  consideration  of  the 
potential  impacts  on  liquidity  in  energy  system  planning,  in  particular  for 
infrastructure investment and decommissioning decisions.56 For example, conversion of 
an existing pipeline to use hydrogen may bring benefits in terms of decarbonisation, but 
there may be a risk that it contributes to a fragmenting of the gas market. Considering 
liquidity impacts explicitly would allow this trade-off to be optimised. It should therefore 
promote ‘least cost’ infrastructure planning decisions in a wider sense.  

There are different aspects to liquidity and so different issues might need to be assessed. 
For example, higher bid-offer spreads may lead to higher transaction costs (which can 
be  quantified  and included  in  a  social  cost-benefit  analysis).  However,  they  may  also 
contribute  (along  with  reduced  availability  of  hedging  products)  to  higher  risks  for 
developers,  which  may  not  be  so  easily  quantified.  Exactly  how  to  include  liquidity 
impacts  in  system  planning,  and  the  balance  between  a  quantitative  and  qualitative 
assessment, would therefore need further consideration.  

We focus above on a fairly limited intervention related to energy system planning, as 
this seems to be one of the areas that can be more easily regulated or legislated for in 
the EU environment. However, it is clear that strategic energy policy at local, national 
or EU level (such as regarding a switchover from natural gas to hydrogen) may have 
wider-ranging  impacts  on  liquidity.  It  is  therefore  also  important  that  energy  policy 
decisions (continue to) consider impacts on market liquidity. 

Figure 43 below summarises our assessment of the option set out above. In summary, 
we would recommend ensuring a more systematic consideration of the potential 
impacts on liquidity in energy system planning (for more detailed assessment and 
policy design work).  

Figure  43  Assessment of  potential solutions to address risk of lack of liquid market for sale of 
heterogenous gases   

Source: See Appendix C for further detail on the assessment. 

5.5.4  UNHARMONISED NATIONAL POLICIES DISTORTING TRADE 

Cross-border competition distortions may result from a range of unharmonised support 
system  set-ups  in  Member  States.  For  instance,  domestic  renewable  and  low-carbon 
gas, which is traded nationally, could be hindered if imported renewable and low-carbon 
gases  not  only  receive  support  in  the  destination  country  but  also  in  the  country  of 
origin.  

56 Liquidity impacts are not, currently, considered in the ENTSOG CBA methodology.  

Page 85 

 
 
 
 
 
                                           
 
 
For  instance,  in  Sweden  biogas  producers  suffer  from  distorted  competition  from 
imported  biogas  since  renewable  gas  producers  receive  policy  support  in  some 
countries. In Sweden, however, support policies target the consumption side, resulting 
in dual support of imported biogas relative to domestic gas. 

Another  example  where  regional  rules  complicate  the  situation  is  international  trade 
between  Baden-Württemberg,  Germany,  and  Denmark.  In  Baden-Württemberg, 
existing  rules  for  biomethane  in  heating  create  concerns  of  double-subsidisation  of 
biogas  produced  in  Denmark  and  consumed  in  Baden-Württemberg.  Namely,  the 
EWärmeG Baden-Würtemberg57 obliges heat demand for houses to be 15% supplied by 
renewable energy. However, subsidies to Danish renewable gas production mean there 
is not a level playing field. Energy suppliers in Baden-Würtemberg may find it cheaper 
to purchase Danish renewable gas (to meet their obligations) since it is subsidised, even 
if other gas sources may entail lower resource costs to society.     . 

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues represent a risk for the achievement of the energy transition and 
would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. We note that State aid control should, in principle, provide an existing tool 
to address such double-subsidy concerns.  

5.5.5  LACK OF COHERENT CROSS-BORDER FRAMEWORK FOR DECOMMISSIONING 

As  explained  in  section  3.3.2,  some  existing  natural  gas  infrastructure  might  be  re-
purposed  for  renewable  and  low-carbon  gases.  However,  overall  gas  demand  is 
expected to fall in the coming decades. While a decrease in gas demand does not lead 
to  a  proportional  decrease  of  infrastructure  needs,  as  the  same  or  most  of  the 
infrastructure may still be needed to satisfy peak supply, there is a possibility that some 
gas infrastructure may require decommissioning going forward. This would be expected 
to  include  cross-border  infrastructure  (i.e.  interconnectors)  as  well  as  other 
infrastructure (such as long-distance transnational pipelines) that is currently used to 
serve load in multiple Member States. 

According to the current cross-border cost allocation framework (under EU Regulation 
347/2013, the “TEN-E Regulation”), the cost of infrastructure will have been allocated 
across  Member  States  depending  on  the  distribution  of  benefits  over  the  expected 
lifetime of the infrastructure. But much of the existing capacity has been built before 
the cross-border cost allocation framework was introduced. This means that the default 
position for older existing infrastructure is that all resulting costs from decommissioning 
may be allocated purely to the country it was built in.58  

This could lead to two potential inefficiencies: 

  Co-ordination issues: Gas infrastructure located within a given Member State 
may influence flows (and costs) in other countries. If individual Member States 
perceive that the benefits of continuing to operate gas infrastructure located in 
their  territory  are  outweighed  by  the  costs  of  doing  so,  they  may  unilterally 
decide  to  decommission  the  assets  in  question.  However,  such  assets  may 

57 EWärmeG BW by ministry of Environment, Climate Protection and the Energy Sector 
https://um.baden-wuerttemberg.de/fileadmin/redaktion/m-
Baden-Württemberg 
um/intern/Dateien/Dokumente/5_Energie/Energieeffizienz/EWaermeG_BW/150317_N
ovelle_Erneuerbare_Waerme-Gesetz.pdf  
58  In  other  cases,  infrastructure  may  have  been  built  with  costs  being  shared  across 
Member States based on the distribution of expected benefits. 

Page 86 

 
 
                                           
 
 
provide  benefits  to  other  countries,  and  might  be  beneficial  from  an  EU-wide 
perspective.   
  Cost-recovery 

the  entire  cost  of 
decommissioning  assets  within  their  territory  (and  these  costs  are  recovered 
from gas users), this may exacerbate issues related to sunk costs weighing on 
gas grid fees (see section 5.2.2 above). 

If  Member  States  bear 

issues: 

This  barrier  has  been  retained  in  the  short  list  of  issues  and  potential  solutions  are 
therefore assessed below.  

Recommendation for lack of coherent cross-border framework for 
decommissioning 

One solution to address the barrier discussed is a framework for co-ordinated cross-
border decommissioning decisions.59 By ‘cross-border’ decommissioning we refer to 
both: 

  Decommissioning of cross-border infrastructure (e.g. an interconnector); and 
  Decommissioning  of  infrastructure  which  affects  flows  across  borders  (e.g. 
decommissioning  storage  in  country  A,  which  may  also  be  used  by  users  in 
country B).60 

To  work,  such  an  option  would  need  TSOs  to  share  information  on  potential 
decommissioning  decisions.  Identification  of  infrastructure  potentially  subject  to 
decommissioning  may  take  place  in  the  context  of  national  development  plans,  and 
subject  to  approval  by  NRAs.  TYNDP  preparation  may  provide  a  forum  whereby 
information on such plans could be shared and their potential implications assessed at 
EU level.  

TSOs  and  NRAs  could  then  jointly  decide  on  action  for  infrastructure  that  may  span 
across (or have impacts across) borders. ENTSOG could derive a ‘decommissioning CBA 
methodology’ (for the infrastructure not subject to CBA and cross-border cost allocation 
to  begin  with).  A  methodology  for  sharing  costs  between  TSOs  (either  in  the  case  of 
decommissioning  or  in  the  case  of  avoided  or  delayed  decommissioning)  would  also 
need to be developed. In the first case NRAs would need to approve (and agree on) any 
cost sharing. However, as is the case for PCIs, ACER could play a role in approving or 
mediating such cross-border cost allocation decisions if needed.  

The main benefit of a cross-border decommissioning framework is that it would provide 
a route to avoiding or delaying the decommissioning of assets that might deliver benefits 
outside  of  the  Member  State  in  which  they  are  located.  This  in  turn  should  lead  to 
reduced costs of gas supply at the EU level and improved security of supply, compared 
to the counterfactual. By providing for more equitable sharing of decommissioning costs 
across borders, it may also help to reduce issues related to dismantling costs weighing 
on gas grid fees (see section 5.2.2). 

Figure 44 below summarises our assessment of the options set out above. In summary, 
we  would  recommend  taking  forward  a  framework  for  cross-border  decommissioning 

59 CEER has outlined a similar process in its “Public Consultation Paper on Regulatory 
Challenges for a Sustainable Gas Sector” dated 22 March 2019 (see section 5.3). 
60  Infrastructure  conversion  decisions  (e.g.  from  natural  gas  to  hydrogen)  are  not 
considered under this heading.  

Page 87 

 
 
 
 
 
 
                                           
 
 
decisions  along  the  lines  described  above  (for  more  detailed  assessment  and  policy 
design work). 

Figure 44 Assessment of potential solution to address lack of coherent cross-border framework 
for decommissioning  

Source: See Appendix C for further detail on the assessment. 

5.5.6  DIFFERENT TIMESCALES FOR ELECTRICITY / GAS MARKETS 

Across the EU, settlement periods for balancing are typically shorter for electricity (15-
30  min)  than  for  gas  (1  hour  –  1  day).  Market  players  may  therefore  have  a  strong 
incentive  to  respond  to  short-term  changes  in  market  conditions  on  the  electricity 
system (e.g. fluctuations in supply due to changing wind conditions). By contrast,  on 
the gas side, players will only need to balance their portfolios on an hourly or daily basis.  

With  growth  in  sector  coupling  technologies  such  as  power-to-gas,  therefore,  it  is 
possible that volatility on the electricity system could induce volatility on the gas system 
(changing output from power-to-gas facilities). Given that players do not need to ensure 
their  gas  positions  are  balanced  over  timescales  shorter  than  an  hour  or  a  day,  gas 
system  operators  will  need  to  carry  out  more  actions  to  ensure  system  stability.  The 
costs  of  such  actions  will  typically  be  socialised  across  gas  market  participants  (as 
opposed  to  being  ‘targeted’  towards  the  players  causing  these  actions).  The  reduced 
incentives  for  participants  to  balance  could  therefore  lead  to  a  higher  overall  cost  of 
balancing the gas system. 

It is not clear, however, whether this will be a significant issue. Gas system operators 
already  face  a  similar  issue  today  with  gas  power  stations  in  systems  with  high  RES 
penetration.  They  are  able  to  manage  risks  given  the  inherent  flexibility  of  the  gas 
system  (for  example,  using  linepack  flexibility).  As  long  as  system  operators  are 
incentivised to minimise costs and have the tools to ensure system stability (e.g. ability 
to buy/sell sub-hourly profiles of gas), balancing costs need not rise excessively. That 
said, we note the problem might become more complex going forwards, with greater 
gas injection taking place at distribution level, where linepack flexibility might be lower.  

This  barrier  has  not  been  retained  in  the  short  list  of  issues  as  part  of  this  study. 
However, these issues may represent a risk for the achievement of the energy transition 
and  would  benefit  from  further  investigation  and  potential  intervention  by  relevant 
authorities. 

Page 88 

 
 
 
 
 
 
6  SUMMARY OF RECOMMENDATIONS 

In  this  section,  we  provide  an  overview  of  recommended  solutions  to  address  short-
listed barriers and gaps.  

We find that, overall, our recommendations can be grouped into five categories: 

  Interventions  via  climate  and  renewable  policy,  and  support  for 
innovation:  this  group  of  solutions  is  designed  to  address  barriers  and  gaps 
related  to  the  relative  immaturity  of  sector  coupling  and  low-carbon  and 
renewable gas technologies; 

  A  regulatory  toolbox  to  address  cost  recovery  issues:  this  group  would 
serve  to  address  barriers  and  gaps  from  group  2,  that  is  to  say  issues 
contributing to an unlevel playing field across technologies; 

  A  number  of  changes  to  market  design  and  charging  arrangements  to 
make them more fit-for-purpose in the face of the expected changes in 
the  sector:  these  would  address  issues  stemming  both  from  the  relative 
immaturity  of  relevant  technologies,  and  the  historic  focus  on  natural  gas  in 
infrastructure regulation; 

  The provision of increased clarity on access to infrastructure would also 
aim to overcome barriers and gaps stemming from the historic focus on natural 
gas in infrastructure regulation; and 

  The 

co-ordinated 

facilitation  of 

infrastructure  planning  and 
decommissioning, which would be expected to help achieve a level playing field 
across  technologies,  avoid  the  risks  of  uncoupled  and  uncoordinated 
infrastructure  planning,  as  well  as  the  risks  related  to  interoperability  across 
markets and borders. 

This is summarised in Figure 45 below.  

Figure 45 Overview of barrier categories and solution categories 

Source: Frontier Economics 

Page 89 

Risk for interoperability across markets and bordersUncoupled and uncoordinated infrastructure planningFocus on natural gas in infrastructure regulationUnlevel playing field due to sector-and technology-specific tariffs and leviesRelative immaturity of relevant technologiesClimate / renewable policy and support for innovationFit for purpose market design and charging arrangementsRegulatory toolbox to address cost recovery issuesCo-ordinated infrastructure planning and decommissioningClarity on access to infrastructureBarriersSolutions/recommendations35421 
 
 
As  explained  above  (in  section  4),  our  recommendations  arise  from  the  qualitative 
research  and  analysis  undertaken  as  part  of  our  assignment.  Given  the  scope  of  this 
study,  neither  detailed  work  on  design  of  individual  policy  options  nor  a  robust 
quantitative assessment of costs, benefits and distributional impacts of all options have 
been carried out. Further work will be needed on these aspects. 

6.1  CLIMATE AND RENEWABLE POLICY AND SUPPORT FOR INNOVATION 

Support for innovation is key to addressing some of the barriers particularly relevant in 
the transition phase for renewable and low-carbon gas technologies.  

Indeed,  (financial)  support  for  Research  and  Development  (R&D),  pilots  or 
demonstration projects and, potentially, beyond that, ongoing support for further 
deployment following the demonstration phase would be a direct way to address 
positive externalities related to innovation. State aid rules and/or internal energy market 
legislation  would  need  to  ensure  that  any  ongoing  support  is  granted  in  a  way  that 
promotes competition and market integration.  

We  see  a  case  for  allowing  network  operator  ownership  (or  involvement  in) 
research-stage or pilot power-to-gas projects in specific circumstances to address 
co-ordination  barriers.  Network  operator  involvement  would  need  to  be  targeted  in 
scope (e.g. limited to understanding technical impacts on the networks) and subject to 
conditions (such as time limits and knowledge sharing) to avoid potential longer-term 
negative  effects  on  competitive  and  market-based  investments.  NRAs  would  need  to 
play an important role in minimising potential negative consequences.  

Power-to-gas ownership by network operators could also be relevant once the 
transition phase has ended, in situations where it is difficult (or disproportionate) 
to ensure market signals convey all possible system benefits (e.g. the benefits of the 
specific location of a facility) well enough. Again, NRAs would play an important role in 
ensuring that such projects would indeed be beneficial for the system and in verifying 
that it is not possible to secure market-based investment. 

6.2  REGULATORY TOOLBOX TO ADDRESS COST RECOVERY ISSUES 

As highlighted in the description of barriers above, the ways in which policy costs (such 
as RES support costs) and the costs of gas infrastructure are recovered matter for the 
uptake of renewable and low-carbon gases.  

A direct solution to the issue of power-to-gas facing end-user taxes on electricity would 
be to ensure that only final electricity consumption faces (cost-recovery) taxes 
and levies. 

Dealing  with  issues  related  to  sunk  and  decommisisoning  costs  requires  a  suite  of 
regulatory solutions. 

To reduce the risk of over-investment in gas infrastructure, leaving asset stranded 
risk with network operators may be an option. However, this may only have limited 
scope  of  application:  for  forward-looking  investments  over  which  network 
operators exercise a degree of discretion (and provided such investments can be 
easily  identified).  For  other  types  of  costs,  more  frequent  (regulatory)  reviews  of 
whether prospective investments are necessary may be beneficial. 

Regarding the distribution of the costs of legacy investment (and of decommissioning 
costs): 

Page 90 

 
 
  To minimise distortions between consumer choices between energy carriers, 
from 

infrastructure  costs  could  be  distributed  away 

sunk 
infrastructure users and towards taxpayers instead.  
If this is not feasible (or not acceptable), ensuring an equitable distribution 
of sunk costs between different energy carriers (i.e. electricity, gas and 
heat) could be an alternative to investigate.  

 

  Allowing  for  faster  recovery  of  costs  (e.g.  accelerated  regulatory 
depreciation) may also be part of the toolkit, although the benefit in terms of 
avoiding distortions to choices between energy carriers is less clear. 

6.3  FIT FOR PURPOSE MARKET DESIGN AND CHARGING ARRANGEMENTS 

Given the historical focus on natural gas, gas market design needs to evolve to efficiently 
accommodate renewable and low-carbon gases into the market. This is particularly the 
case given that much of the new capacity is expected to be connected at the distribution 
level.  

There  are  a  variety  of  connection  charging  approaches  that  avoid  the  first-
mover  disadvantage  while  still  preserving  locational  signals  (to  varying 
degrees). While there may be complexities in their implementation, such options have 
the potential to encourage the development of low-carbon and renewable gases while 
minimising  the  risk  of  incentivising  uptake  of  expensive  connections.  Consistency 
between  the  frameworks  for  connection  charging  and  for  dealing  with  connection 
requests (see “Clarity on access to infrastructure” below) would be important.  

The  creation  of  harmonised  injection  charging  rules  (at  distribution  level)  would 
increase certainty for developers regarding how they might be charged for use of the 
gas grid, in turn reducing the costs across the EU of deploying renewable and low-carbon 
gases.  

Successful integration of renewable and low-carbon gases into the market also requires 
that the framework for managing physical congestion is complete (in particular 
at distribution level). 

  Competitively  tendered  voluntary  agreements  between  network 
operators  and  participants  to  limit  injections  may  be  a  relatively 
straightforward measure to implement. 

  More  sophisticated  market-based  systems  allowing  for  real-time 
adjustment  of  bids  may  offer  greater  efficiency,  but  may  not  be  a 
proportionate solution if congestion issues remain limited. 

  Obliging participants to limit injections may be appropriate in situations 
where  there  may  be  a  limited  number  of  options  to  address  localised 
congestion issues, leading to possible market power concerns. 

6.4  CLARITY ON ACCESS TO INFRASTRUCTURE 

Many of the barriers historically stemming from the regulation on natural gas could be 
addressed through greater clarity on the access for new gases to infrastructure.  

To reduce the risks to developers from uncertainty regarding quality standards, it would 
first be important to provide improved visibility on gas quality for gas producers. 
Clear rules on how quality is managed on an ongoing basis (such as the potential 
impacts  on  connection  requests  or  on  interruption  of  production  and  possible 
compensation) would help to further reduce risks.  

Page 91 

 
 
 
 
The  first  step  in  addressing  TSOs’  incentives  to  focus  on  gases  compatible  with  their 
infrastructure  would  be  a  review  of  regulatory  frameworks  to  identify  such 
biases.  An  additional  specific  (but  partial)  solution  might  be  an  obligation  for 
network  operators  to  connect  renewable  and  low-carbon  gas  sources  to  the  gas 
system, provided certain conditions (specified in advance, such as regarding gas quality) 
are met.   

Finally,  clarifying  whether  (and  under  what  conditions)  the  provisions  of  the 
Gas Directive apply to hydrogen (and other gases) is likely to provide increased 
clarity for developers regarding their ability to secure access to infrastructure, reducing 
the risks to investment. 

6.5  CO-ORDINATED INFRASTRUCTURE PLANNING AND DECOMMISSIONING 

Improved co-ordination in planning and decommissioning decisions can help to 
improve the efficiency with which infrastructure is used. It could also help to improve 
interoperability across markets and sectors.  

An assessment of the implications of the expected change in the role of gas as 
well  as  the  mix  of  technologies  on  the  likely  optimal  level  of  gas  storage 
capacity would be a first step in addressing some of the uncertainty related to storage, 
and could provide a basis for assessing whether further intervention is needed.  

Co-ordinated  infrastructure  planning  (between  transmission  and  distribution 
level, and between electricity and gas networks) would allow operators to arrive 
at  a  shared  view  on  possible  developments  in  demand  and  supply  and  identify  and 
evaluate  investment  possibilities  in  different  parts  of  the  system.  This  would  be  an 
important enabler of lower costs. Regulatory incentives on individual operators to 
achieve cost savings at system level may provide the mechanism for ensuring any 
potential cost savings identified are actually achieved.  

Ensuring a more systematic consideration of the potential impacts on liquidity 
in  energy  system  planning,  in  particular  for  infrastructure  investment  and 
decommissioning decisions, would allow liquidity impacts to be traded off against other 
costs  and  benefits.  This  should  therefore  promote  ‘least  cost’  infrastructure  planning 
decisions in a wider sense. 

A framework for cross-border decommissioning decisions could provide a route 
to  avoiding  or  delaying  the  decommissioning  of  assets  that  might  deliver  benefits 
outside of the Member State in which they are located. By providing for more equitable 
sharing  of  decommissioning  costs  across  borders,  it  may  also  help  to  reduce  issues 
related to dismantling costs weighing on gas grid fees. 

Page 92 

 
 
 
  Regulatory  barriers  and  gaps:  detailed 
information on the research methodology and tools  

Business Scenarios  

We  also  take  a  micro  perspective  of  stakeholders  dealing  with  specific  relevant 
technologies and respective business scenarios. We therefore ordered the barriers we 
had found in the country-based research along the value chain. The steps in the value 
chain are a) production, an area where revenues stem from commercial activities, b) 
transmission and distribution, an area where revenues are regulated, c) storage and d) 
end use, areas where revenues come from a mix of regulated and commercial activities. 
By structuring the barriers this way, we ensured that we do not miss a barrier that is 
specific to the interaction between different steps in the value chain.  

Figure 46 

Structure following the value chain of a technology along business scenarios  

Source: Frontier Economics 
Note: The business sceanrios are a small set of examples and aim to capture different 
perspectives, but they do not aspire to include all possible business scenarios. 

2019 

Directorate-General for Energy  
Internal Energy Market 

End useStorageTransmission/ distributionProductionMix of regulatory and commercial costs / revenuesRegulated activities –costs and revenuesCommercial activities –cost and revenues1.T-connected PtG facility (electrolysis) injecting gas (CH4 or H2) into dedicated gas infrastructure serving (industrial) final consumers2.D-connected PtG facility (electrolysis) injecting gas (CH4 or H2) into existing gas D-grid (no direct link to final consumer)3.Biomethane injection facility injecting into existing gas grid (T or D, no direct link to final consumer)4.D-connected power-to-gas-to-power storage facility (hydrogen) with dedicated on-site gas storage, arbitraging between off-peak and peak electricity prices5.Imported hydrogen produced from natural gas using CCS flowing through the transmission grid. 
 
 
 
 
 
 
 
  Regulatory barriers and gaps: overview 

of the major findings of the country-based research   

Selection of countries 

The country-based research covers: 

  The largest gas markets (by consumption) in the EU: the UK, Germany,  Italy, 

France, the Netherlands, Spain and Poland 

  Countries with high RES potential, e.g.  

-  UK, Denmark, Germany, the Netherlands, for wind;  

-  France, Greece, Italy and Spain for solar 

  Countries with large biogas potential: e.g. France, Italy, Denmark 

  Countries  with  high  district  heating  coverage:  Czech  Republic,  Denmark, 

Slovakia and Lithuania 

  Certain countries to ensure a diverse geographical sample: Greece and Bulgaria 

Figure 47 

Country selection  

Source: Eurostat 2016 

The country-based research includes the systematic review of regulation with a view 
to identify potential barriers and gaps. Therefore we used the knowledge of our own 
country experts and identified pilot projects (see the Intermediate Report) and 
interviewed participating parties and analysed their feedback. Figure 48 gives an 
overview of the information collected as part of this exercise. 

The table below explains the categories of information presented in Figure 48. 

Page 94 

 
 
 
 
 
 
 
 
Topic 
Current role of gas 
in % of final energy demand 
Demonstration/pilot projects 

for biogas/-methane 

for  renewable  or  fossil-
based hydrogen 
Technical regulation / access 
Gas  quality  standard  covers 
biomethane 
Gas  quality  standard  covers 
hydrogen 
Definition  exists 
methane, hydrogen 
Limit for H2 blending in place 

for  biogas/-

rules 

for  biogas, 

for  H2  and  H2 

Regulation 
infrastructure in place 
Priority  access  for  biomethane, 
hydrogen 
Curtailment 
hydrogen 
Unbundling  and  TPA  applies  to 
biogas and hydrogen 
Tariffs 
Connection  cost  liability  TSO  and 
DSO 
Specific network tariffs for biogas 
and hydrogen 
Infrastructure regulation 
Depreciation  period 
infrastructure 
Decommissioning cost liability 

for  gas 

SoS and flexibility 
Storage obligation in place 
Capacity  mechanism  in  place  + 
participation  by  gas  sector  / 
Power-to-Gas 
Balancing  markets  -  participation 
by gas sector / Power-to-G 

Renewable and climate policy 
Targets: 
specific 
renewable hydrogen 
GoOs for biogas 
GoOs for renewable hydrogen 

for  biogas, 

Percentage of final energy demand met by gas. 

Are there any pilot projects for biogas production 
and/or biomethane injection to the grid? 
Are  there  any  pilot  projects  for  hydrogen 
production and injection to the grid? 

Does  a  national 
biomethane? 
Does a national specification exist for hydrogen?  

specification  exist 

for 

Are  low-carbon  and  renewable  gases  defined  in 
national law / regulation? 
Has there been an assessment of the amount of 
H2 it is possible to blend with natural gas in the 
grid? 
Is there tariff regulation for H2 infrastructure? 

Is there priority access for renewable gases?  

Are  rules  (and  compensation)  defined  for  the 
interruption of gas injection to the grid? 
Does national regulation provide that third party 
access and unbundling necessarily applies? 

Are renewable gas producers required to pay for 
connection costs to the grid? 
Is low-carbon and renwable gas injection subject 
to a different network tariff structure? 

What  is  the  average  remaining  life  of  gas  grid 
assets? 
How  are  infrastructure  decommissioning  costs 
expected to be recovered? 

Are there obligations to hold storage capacity? 
Where a capacity remuneration mechanism is in 
place,  can  renewable  and  low-carbon  gas-fired 
capacity participate in capacity mechanisms? 
Could power plants running on renewable or low-
carbon  gases  participate  in  reserves  or  the 
balancing market? 

Have sector-specific targets been set? 

Are guarantees of origin established for biogas? 
Are  guarantees  of  origin  established 
renewable hydrogen? 

for 

End-user taxes for electricity, gas  Are there energy and carbon taxes on natural gas 

Power-to-Gas exempted? 

and electricity? 
Would  power-to-gas  facilites  be  exempted  from 
end-user taxes?  

Page 95 

 
 
 
 
 
 
 
 
 
 
 
Figure 48 

Country-based research overview  

NE = not evidenced 

Topic 

Bulgaria 

Czech 
Republic 

Denmark 

France 

Germany 

Great Britain  Greece 

Current role of gas 
in % of final energy demand 
Demonstration/pilot projects 

13% 

for biogas/-methane 
for  renewable  or  fossil-based 
hydrogen 

NO 

NO 

NO 
NO 

Technical regulation / access 
Gas quality standard covers biomethane  NO 
NO 
Gas quality standard covers hydrogen 
Definition  exists  for  biogas/-methane, 
hydrogen 
Limit for H2 blending in place 
Regulation  for  H2  and  H2  infrastructure 
in place 
Priority 
hydrogen 
NO 
Curtailment rules for biogas, hydrogen  NE 
Unbundling  and  TPA  applies  to  biogas 
and hydrogen 
Tariffs 
Connection cost liability TSO and DSO61  100% 
Specific  network  tariffs  for  biogas  and 
hydrogen 

biomethane, 

access 

YES 

NO 

NO 

for 

23% 

NO 

YES 

NO 
NO 

NO 
NO 

NO 

NO 
NO 

NO 

NE 

NO 

10% 

YES 

YES 

YES 
YES 

NE 
YES 

NE 

NE 
NE 

NO 

0% 

NE 

20% 

NO 

YES 

YES 
NO 

YES 
YES 

NO 

NE 
NO 

NE 

40% 

NO 

25% 

YES 

YES 

YES 
YES 

YES 
YES 

YES 

YES 
NO 

YES 

75% 

YES 

29% 

NE 

YES 

NE 
NE 

YES 
YES 

NE 

NO 
NE 

NO 

0% 

NE 

6% 

NE 

NO 

NE 
NO 

NE 
NE 

NE 

NO 
NO 

NE 

NE 

NE 

61 Remaining connection cost to be paid by the facility operator  

Page 96 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                           
 
 
Topic 

Bulgaria 

Czech 
Republic 

Denmark 

France 

Germany 

Great Britain  Greece 

Infrastructure regulation 
Depreciation 
period 
infrastructure 

for 

gas 

Pipelines 
Other equipment 
Decommissioning cost liability 
SoS and flexibility 
Storage obligation in place 
in  place  + 
Capacity  mechanism 
participation  by  gas  sector  /  Power-to-
Gas 
Balancing markets - participation by gas 
sector / Power-to-G 
Renewable and climate policy 
Targets:  specific  for  biogas,  renewable 
hydrogen 
GoOs for biogas 
GoOs for renewable hydrogen 
End-user taxes for electricity, gas 

Power-to-Gas exempted? 

35 
15 
NE 

YES 

NE 

NE 

NO 
NO 
NO 
YES 
NO 

NE 
NE 
NE 

YES 

NO 

NE 

NO 
NO 
NO 
YES 
NO 

30 
NE 
TSO 

NO 

NE 

NE 

NO 
YES 
YES 
YES 
NE 

NE 
NE 
NE 

YES 

NE 

NE 

YES 
YES 
NE 
YES 
YES 

30-40 
NE 
NE 

NO 

NO 

NE 

NO 
YES 
YES 
YES 
YES 

45 
NE 
NE 

NO 

YES 

NE 

NO 
YES 
NO 
YES 
NE 

40 
NE 
NE 

NO 

NE 

NO 

NO 
NO 
NO 
YES 
NE 

Page 97 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Topic 

Italy 

Lithuania 

Poland 

Slovakia 

Spain 

The 
Netherlands 

Current role of gas 
in % of final energy demand 
Demonstration/pilot projects 

for biogas/-methane 
for  renewable  or  fossil-based 
hydrogen 

37% 

YES 

NO 

NO 
NO 

Technical regulation / access 
Gas quality standard covers biomethane  YES 
YES 
Gas quality standard covers hydrogen 
Definition  exists  for  biogas/-methane, 
hydrogen 
Limit for H2 blending in place 
Regulation  for  H2  and  H2  infrastructure 
in place 
Priority 
YES 
hydrogen 
Curtailment rules for biogas, hydrogen  NO 
Unbundling  and  TPA  applies  to  biogas 
and hydrogen 
Tariffs 
Connection cost liability TSO and DSO 
Specific  network  tariffs  for  biogas  and 
hydrogen 

biomethane, 

access 

NO 

NO 

NO 

for 

0-20% 

11% 

NO 

NO 

YES 
NO 

YES 
YES 

NO 

NO 
YES 

YES 

40% 

NO 

14% 

NO 

YES 

NO 
NO 

YES 
NO 

NO 

NO 
YES 

YES 

0% 

NO 

25% 

NO 

NO 

YES 
NO 

YES 
YES 

NO 

NO 
YES 

YES 

75% 

NO 

NE 

NO 

NO 

NO 
NO 

YES 

NO 

NO 

NO 

NO 

NE 

NO 

NE 

YES 

YES 

YES 
YES 

YES 

NO 

NO 

YES 

NO 

NE 

NE 

Page 98 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Topic 

Italy 

Lithuania 

Poland 

Slovakia 

Spain 

Infrastructure regulation 
period 
Depreciation 
infrastructure 

for 

gas 

Pipelines 
other equipment 
Decommissioning cost liability 

50 
NE 
Consumers 

55 
4-60 
TSO/DSO 

NE 
NE 
Consumers 

40-50 
12-50 
TSO/DSO 

SoS and flexibility 
Storage obligation in place 
in  place  + 
Capacity  mechanism 
participation  by  gas  sector  /  Power-to-
Gas 
Balancing markets - participation by gas 
sector / Power-to-Gas 
Renewable and climate policy 
Targets:  specific  for  biogas,  renewable 
hydrogen 
GoOs for biogas 
GoOs for renewable hydrogen 
End-user taxes for electricity, gas 

Power-to-Gas exempted? 

YES 

YES 

YES 

YES 

NO 

YES 

NO 
YES 
NE 
YES 
NE 

NO 

YES 

NO 
NO 
NO 
YES 
NE 

YES 

YES 

NO 
NO 
NO 
YES 
YES 

NO 

YES 

NO 
NO 
NO 
YES 
YES 

NE 
NE 
NE 

YES 

YES 

NO 

NO 
NO 
YES 
NO 

The 
Netherlands 

32 
NE 
Infrastructure 
owner 

NO 

NO 

YES 

YES 

YES 
NO 
YES 
NO 

Page 99 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Detailed information on solutions assessment 

Page 100  

1Contents1.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
 
Page 101  

21.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
Page 102  

3Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesPositiveMixed / NeutralNegativeBenefits outweigh costs.Indicates lower magnitude of impacts.Balance of costs and benefits neutral or uncertain. Costs outweigh benefits.Indicates lower magnitude of impacts. Positive for all investors; reduces riskMixed or neutral impacts on investorsNegative for investors; increases riskReduces bills unambiguously; positive for fairness and choiceMixed or neutral impactsBills increased; negative for fairness and choice Low risk of unintended consequences; implementation time ≤1 yearMedium risk of unintended consequences OR 2-4 years for implementationHigh risk of unintended consequences OR ≥5 years for implementationClear case for co-ordinated EU actionUncertain / limited gain to co-ordinated EU actionNo gain to co-ordinated EU actionMethodology: Assessment of individual categories 
 
 
 
Page 103  

41.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
Page 104  

5Assessed solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologiesRelative immaturity of relevant technologiesClimate / renewable policy for innovationFit for purpose market design and charging arrangementsSolutions assessed from categories:Barrier category:Lack of internalisation of positive externalities from innovation / learningFirst-mover disadvantage –high infrastructure connection costsSupport for R&D, pilots or demonstration projects1.1.1Network operator involvement in power-to-gas projects where difficult to ensure market signals convey all possible system benefits1.1.51.1Network operator involvement in research-stage or pilot power-to-gas projects1.1.4Ensure ongoing support promotes competition and market integration1.1.2EU-wide gas-sector specific targets1.1.3Shallow connection costs (transitional)1.2.2Sharing of connection costs across multiple connections (actual or projected)1.2.11.4 
 
 
 
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6The counterfactual is uncertain, and depends on the amount of innovation funded by Member States. Investment costs and operating costs associated with innovation projects entail a resource cost to society. To the extent such projects deliver environmental and security of supply benefits themselves, some of this cost may be offset in the short run by avoiding the costs of alternative measures to meet environmental and security of supply goals. In the short-run, it might be reasonable to expect there would still be a net cost to society associated with these projects. However, over the long-run, the costs of some supported technologies should fall (assuming technologies that fail to reduce costs stop being supported) and the number of technological options available should increase. Taken together, this increases the likelihood that, over the long-term, environmental and security of supply goals can be met at lower cost.To maximise benefits, a robust selection process will be central, noting that the nature of innovation means there is still a risk that some supported technologies may not prove beneficial (or may not reduce their costs).Lack of internalisation of positive externalities from innovation / technology spillovers / learning: Assessment of recommendationsSupport for R&D, pilots or demon-stration projectsIncreased certainty over available funding may help to attract private sector finance into projects, given riskiness of early stage investments.Consumers will bear higher costs in the short run. The distribution of costs depends on how support for technologies is funded (i.e. energy prices vs. general taxation, which energy carrier).Overall, consumers should benefit over the longer-term from cost reductions in the energy system (with benefits concentrated on those consumers using the supported technologies). Greater innovation could also lead to greater consumer choice. For EU-wide funding (and in many MS), institutions to manage innovation funding are already in place (e.g. Innovation Fund), making it relatively quick to implement. To ensure benefits, innovation funding needs to be well-managed. In particular, there is a risk of picking the ‘wrong’ winners and/or capture by vested interests. EU-wide funding may address the potential risk of individual MS not being fully in-centivised to fund innovation due to benefits spilling over to other countries.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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7Lack of internalisation of positive externalities from innovation / technology spillovers / learning: Assessment of recommendationsEnsure ongoing support promotes competition and market integrationIn the counterfactual, we assume there are no specific rules governing what form support schemes for renewable and low-carbon gases should take. This means that schemes introduced by MS may have less emphasis on the use of competitive tendering, technology neutrality and cross-border participation. There may also be less emphasis on market integration –support schemes may, for example, require TSOs/DSOs to manage producers’ output, rather than producers/shippers being responsible for finding a route to market and ensuring balance. Increased emphasis on competitive tendering, technology neutrality and cross-border participation should in principle lead to greater efficiency (increasing the likelihood that projects supported are those that entail the lowest resource cost to society). This may be partially offset by a potential increased cost of capital, though we think this can be minimised (see ‘Investment environment’).While players may perceive additional risk if obliged to ensure flows are in balance and to procure the appropriate amount of capacity, this risk transfer is likely to be efficient since they are probably better-placed to manage these risks than network operators. For example, shippers can contract with producers who are better able to forecast and help balance. The resulting incentives for producers should lead to measures being taken that help to reduce costs of balancing the system both in the short-and long-run.On the one hand, greater certainty on assessment framework could help investment. On the other hand, investors may perceive increased risk from competitive tendering and direct marketing.The risk from competitive tendering can be minimised if support is allocated at a sufficiently early stage of project development.Overall, reduced costs in the energy system should lead to overall lower costs for consumers.Some time required for thinking done on RES-E to be adapted for gases. But overall not radical departure from current arrangements.Design of cross-border support schemes will need careful consideration to achieve efficient outcomes where underlying market arrangements (e.g. connection charging) are not harmonised. State aid guidelines and/or EU gas market legislation would need to be updated. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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8Lack of internalisation of positive externalities from innovation / technology spillovers / learning: Assessment of recommendationsIn the counterfactual, we assume that at EU level there are targets for decarbonisation, overall renewable energy and energy efficiency, but no gas-sector specific targets. Member States may have their own targets. The net effect of an EU-wide gas sector-specific target is uncertain. Decarbonisation and renewable goals may still be met under the counterfactual. Gas sector-specific targets may (if binding) simply result in an additional constraint for the EU (or individual MS) to meet, resulting in higher costs associated with meeting decarbonisation, renewable and energy efficiency goals.There is a possibility that, if sector-specific targets address a possible political engagement barrier (that can otherwise not be solved through existing or potential reforms to Energy Union governance arrangements), they may increase the likelihood that energy and climate goals (particularly in the non-traded sector, where there is no ‘cap and trade’ system) are met. EU-wide gas sector-specific targetsA target would provide greater certainty for those developers falling in its scope but potentially lower certainty for those out of its scope. As noted (see ‘net societal’ costs), there is a risk that costs in the energy system could increase, which would ultimately feed through into higher energy prices for consumers. New sector-specific targets would be a significant change relative to the status quo, likely requiring substantial consultation and analysis regarding the level of any targets and their design.If targets are not Member State-specific, governance arrangements will be needed to ensure Member State contributions add up to any EU target for gases.EU action would be required to introduce a binding EU-wide target. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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9Lack of internalisation of positive externalities from innovation / technology spillovers / learning: Assessment of recommendationsNetwork operator involvement in research-stage or pilot power-to-gas projectsIf intervention targeted to areas where network operators may have a greater incentive to act compared to other players (e.g. researching impacts of gases on network) and if co-ordination with other players is otherwise difficult, this could lead to greater research into and deployment of power-to-gas technologies.This should in turn ultimately reduce costs of decarbonisation in the long run (see assessment for ‘R&D / pilots / deployment support + innovation incentives for network operators’), assuming that any learning from such projects is made available to other market participants. TSOs might also have greater incentives to finance projects if there is a possibility of system benefits being significant. If/when this is established, possible mechanisms for rewarding delivery of these benefits (by non-regulated players) might be investigated (see next slide for more details). The assessment of a potential net benefit assumes that potential negative consequences (see ‘Investment environment’ and ‘Complexity and timelines’) can be limited. There is a risk that allowing TSO participation could deter investment from non-regulated entities (since they are not able to access finance on similar terms). A further deterrent may arise if grid operators are allowed to sell output from such projects could be on the market (to ensure efficiency), .The risks might be mitigated to the extent that deployment levels do not reach significant quantities and intervention is targeted to cases where there may be co-ordination barriers in the initial stages of technology development.In the short term, additional costs may be recovered through grid fees, leading to an increase in bills for consumers. Over long-run, energy consumers as a whole should benefit from lower costs in the energy system resulting from innovation.Which consumers bear the costs (electricity or gas) depends on which grid operator carries out the investment and how the benefits are distributed across the gas and electricity systems. The degree of change and timescale required depends on whether legislative changes are required.The role of NRAs in approving funding could help to limit unintended consequences –in particular ensuring that projects are limited to R&D relevant to networks and ensuring that network operators do not engage in projects that  might allow them to benefit from market power. May involve changes to EU legislation (for example regarding un-bundling).  There may also be a role for EU funding to ensure innovation is not con-centrated in a few Member States. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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10Lack of internalisation of positive externalities from innovation / technology spillovers / learning: Assessment of recommendationsInvestment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesNetwork operator involvement in power-to-gas projects where difficult to ensure market signals convey all possible system benefitsUnder the counterfactual, potential barriers may prevent market players from capturing system benefit (as well as commercial benefit). This includes the potential difficulty or inability to amend market design to allow capture of such benefits by market players. This may lead to under-investment in power-to-gas technologies compared to what would be efficient.Allowing network operator ownership in such circumstances could therefore lead to system benefits being maximised (i.e. lower costs of operating networks), provided they face incentives to realise such benefits. Such benefits may be highly location-specific. The assessment of a potential net benefit assumes that ways can be found to allow such projects to realise both commercial and system benefits (required to ensure efficiency), while limiting the potential for negative consequences (see ‘Investment environment’ and ‘Complexity and timelines’). Ownership could either be by electricity or gas network operators. Different types of operator may choose different locations for developing power-to-gas installations. Co-ordination and communication between operators would be important to ensure benefits are maximised.The measure would be positive for TSOs, as they would be able to increase investment, on which they could earn a rate of return. However, there is a risk that if market design improvements were indeed a viable alternative, that other players are prevented from carrying out investments they might otherwise have done. And market players may be negatively affected if network operators can sell output from the facilities on the market.Provided that both system and commercial benefits can be realised by such projects, this should help to reduce overall costs across the energy system, in particular those associated with system management. Ultimately this should feed through to lower energy costs for consumers, though different consumers (e.g. electricity or gas) may benefit differently. Legislative changes are likely to be required.The role of NRAs in approving grid operator ownership could help to limit market distortions –for example ensuring that network operators’ involvement is limited to projects that are socially desirable and where changes to market design or not feasible or proportionate and in which market players cannot be attracted to invest (for example by applying a ‘market test’).May involve changes to EU legislation (for example as regards un-bundling).  
 
 
 
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11First-mover disadvantage –high infrastructure connection costs including ‘deep’ costs: AssessmentSome degree of regional harmon-isation of approach may be beneficial. However, the value of co-ordinated action across the whole EU is not clear. Connection charges often result from a 2-stage analysis. The first step is to calculate costs that should in principle be faced by individual connections (shallow or deep depending on the local framework). The second step is to compare this with expected tariff revenue from connections (which may include assumptions on factors such as future take up). Finally, a decision on what proportion of the costs (in step 1) to actually charge a given connection is made.Such approaches lead to a reduction in the costs borne by individual connections (for example due to spreading of costs over expected connections). As described above for shallow charging, this has the potential to lead to higher deployment of renewable and low-carbon gases, particularly in the steady state.Compared to shallow charging, however, charges would be more cost-reflective, and it may be possible (depending on precise design) to largely avoid incentivising expensive connections.Sharing of connection costs across multiple connections (actual or projected)This might be viewed positively by investors in renewable and low-carbon gases. As for shallow charging, it does not guarantee that network owners can recover expenditure, although the risk should be lower than for shallow charging. Customers face potentially higher network tariffs required to cover additional connection costs.Given the effect on deployment of renewable and low-carbon gases is uncertain, this is  a source of further uncertainty around the short-and long-term costs to consumers.Potentially some complexity in implementation. Risk of incentivising expensive connections (within regions) might remain.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
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12We assume in the counterfactual that some MS adopt a ‘pure’ deep connection charging approach. The main risk of shallow charging is that it could result in connections being encouraged that entail higher resource costs to society. Another issue to consider is whether costs and benefits are affected via the impact of a move to shallow charging on deployment of renewable and low-carbon gases. Here, the impacts are less certain.In the transitional phase while projects are still supported, support levels are likely to reduce in response to reductions in the costs of developing renewable and low-carbon gas production, with an unclear result for levels of deployment. In the steady-state, deployment may increase if costs to developers fall, since gas prices (the main driver of revenue) are likely to be determined more by global/regional factors. But the impact on costs and benefits is unclear, since additional deployment of renewable and low-carbon gases means other investments can be avoided and renewable and decarbonisation goals can still be met. First-mover disadvantage –high infrastructure connection costs including ‘deep’ costs: AssessmentShallow connection costs (transitional)Shallow connection charging might be viewed positively by investors in renewable and low-carbon gases. However, it does not guarantee that network owners can recover expenditure (unless connections can be refused). Customers face potentially higher network tariffs required to cover additional connection costs not charged to sites. Given the effect on deployment of renewable and low-carbon gases is uncertain, this is  a source of further uncertainty around the short-and long-term costs to consumers. The main risk lies in incentivising higher-cost connections. Some degree of regional harmon-isation of approach may be beneficial. However, the value of co-ordinated action across the whole EU is not clear. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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131.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
 
 
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14Assessed solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and leviesRegulatory toolbox to address cost recovery issuesUnlevel playing field due to sector-/ technology-specific tariffs and leviesSolutions assessed from categories:Barrier category:Co-ordinated infrastructure planning and decommissioningFramework for co-ordinated cross-border decommissioningMore frequent regulatory review of necessary investments in gas infrastructureState funding / guarantee for sunk and/or dismantling costsFlexibility for gas sunk or dismantling costs to be spread across users of other energy carriersLeave asset stranding risk with network operators (discretionary investments only)Leave asset stranding risk with network operators (all costs)Taxes/levies on final electricity consumption only2.1.12.2.12.2.22.2.32.2.42.2.52.2.7Power-to-gas facing end-user taxes on electricity2.1Sunk / dismantling costs of gas infrastructure weighing on gas grid fees2.2Regulatory measures that allow for faster recovery of capex2.2.6 
 
 
 
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15In the counterfactual, some power-to-gas facilities may still face (cost-recovery) taxes and levies on electricity consumption. Ensuring only final electricity use faces such taxes would place power-to-gas (and steam methane reforming) facilities on a level playing field compared to other renewable and low-carbon gas production (such as biomethane). Private investment (and operational) decisions on which technology in which to invest therefore no longer need to take into account such taxes/levies. Absent other distortions, this enables investor choices to be more in line with what is most cost-effective from a societal perspective. Overall, therefore, we would expect lower costs to society of achieving energy policy objectives. Power-to-gas facing end-user taxes on electricity: AssessmentTaxes/levies on final electricity consumption onlyThis would be positive for investors in power-to-X (and steam methane reforming).There is a risk, if implemented as a ‘tax exemption’ (as opposed to a fundamental change of tax base), that investors could perceive a higher risk of reversion to the original policy. Overall, and over the long-run, consumers should face lower prices, due to lower costs in the energy system. However, in the short run, (final) electricity consumers might pay more, to the extent electricity taxes/levies that would have been paid by power-to-gas facilities are redistributed among final consumers. Changes to taxes can be done relatively quickly in many Member States. Though defining what counts as ‘final’ electricity consumption may need careful consideration. MS may desire clarity that this would be allowable under EU legislation (State aid rules and Energy Taxation Directive).Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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16Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentRequires individual NRA decision onlyThe measure would require only an individual NRA decision to implement; the gains from co-ordinated EU action are not clear. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesMore frequent regulatory review of necessary investments in gas infra-structureThis measure gives the potential for improved avoidance of investments that are not beneficial from a societal perspective. This should result in lower costs within the energy system. May give grid operators more certainty of ability to recover costs –since investments should be based on better evidence of whether they are actually needed.Consumers avoid paying for investments that might no longer be needed. 
 
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17Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentLeave asset stranding risk with network operators (dis-cretionary investments only)On the one hand, TSOs bearing this risk could lead to higher costs (due to higher cost of capital) of the investments that are carried out. On the other hand, bearing this risk could lead to them being more cautious regarding planned investments, avoiding making investments that could be potentially stranded in the future (reducing costs to society).In principle some transfer of risk should be efficient, since investors are better-placed to manage the risks of demand being insufficient compared to the investment being made, to the extent investment goes beyond what might be needed to ensure security of supply or other policy goals. In practice (see ‘complexity’) identifying the point at which investments become discretionary may be complex. The significance of this impact is uncertain. In principle it would only apply to the fraction of new investment that was discretionary, although as discussed (see ‘complexity’) identifying this proportion would not be straightforward. Investors would take on additional risk. On the other hand, this would be limited to risks they would be better-placed to anticipate and they should also be compensated for the additional risk (for example, in the form of a higher cost of capital allowance). On the other hand, a lower volume of investment may result in lower profits. The net effect for consumers (or taxpayers) is uncertain. On the one hand, they may bear fewer costs associated with stranded investments. On the other hand, a higher cost of capital allowance for investors could result in higher tariffs to support the investments that are carried out. Identifying the ‘discretionary’ component of an investment may not always be straightforward. For example, an investment may serve policy or security of supply goals. But it may include additional features that may only be profitable based on a relatively optimistic forecast of demand. Deciding on an approach to adjusting the cost of capital may be a novel issue for regulators and take some time to implement. Difficult for EU to mandate the approach that should be taken here (for example how the rate of return should be adjusted).Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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18Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentLeave asset stranding risk with network operators (all costs)Bearing this risk could lead to TSOs being more cautious regarding some planned investments over which they exercise discretion, avoiding making investments that could be potentially stranded in the future (reducing costs to society).However, bearing this risk could lead to higher costs to society (arising from a higher cost of capital associated with risks that TSOs are less well-placed to manage –see ‘Investment environment’). Alternatively, TSOs may invest less going forward (if allowed to), potentially leading to lower levels of security of supply and/or higher costs elsewhere in the energy system of transporting and storing energy.Overall, therefore, costs to society could increaseInvestors may be required to bear risks that they may not be well-placed to manage (for example, the risks that investments will no longer be required if there is a significant change in public policy in the gas sector, or the risk of stranding for mandatory investments). A retrospective change in the degree of stranding risk may also drive an increase in the cost of capital in the wider economy, in particular in other regulated sectors. Users of gas infrastructure may see their contribution to the recovery of sunk costs reduce. However, the overall cost of financing infrastructure will increase due to the increase in the cost of capital required by TSOs.Consumers in other sectors could be negatively affected if perceptions of increased risk spread across the wider economy.Deciding on an approach to adjusting the cost of capital may be a novel issue for regulators and take some time to implement. As noted under ‘investment environment’, there is a strong risk of unintended consequences from such a measure. Difficult for EU to mandate the approach that should be taken here (for example how the rate of return should be adjusted).Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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19Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentState funding / guarantee for sunk and/or dismantling costsThe costs grid users face will be closer to being fully cost-reflective (i.e. reflecting forward-looking costs only). This means their incentives (and resulting choices) are better aligned with what will be least-cost from a system perspective.Sunk (and/or dismantling costs) can be recovered using the full flexibility of the tax system. For example, there may be a potential to shift sunk cost recovery towards those goods/services for which demand is less responsive to changes in price (‘more inelastic’). This can help to minimise the welfare losses to society from taxation. The tax system can also be used to ensure a more equitable distribution of costs (see ‘consumer protection’). The measure would reduce risks for investors in gas, without significantly increasing risks for other energy carriers. Lower-income households tend to spend a greater proportion of their income on energy. So network tariffs can be viewed as a ‘regressive’ tax. Shifting the burden of cost recovery towards general taxation may help ensure a more equitable distribution of costs.Tax decisions can be made relatively quickly. However, it may be politically challenging to re-distribute costs across taxpayers. In addition, there may be State aid implications (see ‘EU value-added’).Unclear value to co-ordinated EU action. Question of whether taxpayer funding or a State guarantee would constitute a ‘new’ or ‘additional’ protection that might need approval under State aid rules. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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20Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentFlexibility for gas sunk or dismantling costs to be spread across users of other energy carriersCompared to the counterfactual, the possibility of re-distributing (gas network) sunk cost recovery charges to other energy carriers could help to minimise distortions. In particular, it allows for the possibility of pure ‘cost recovery’ charges to be adjusted such that consumer choices between energy carriers are not distorted by sunk cost recovery (consumers should still face ‘cost reflective’ charges). Absent other distortions affecting the prices consumers face, this enables their choices to be more in line with what is most cost-effective from a societal perspective. Overall, therefore, we would expect lower costs to society of achieving energy policy objectives. The measure could be positive for investors in gas, but be viewed negatively by investors in electricity / heat. The measure mainly involves a possible redistribution of costs between consumers. Consumers with a gas connection may end up paying less overall for energy supplies, while those without a gas connection may pay more overall. Question as to whether EU legislation needs to change to allow this (see ‘EU value-added’). Risk of inefficient outcomes in implementation (e.g. if too much of the burden of sunk cost recovery is placed on other energy carriers)Question whether this would be allowable under EU legislation (for example TAR NC rules preventing cross-subsidy, or under State aid rules).Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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21Sunk costs and dismantling costs of gas infrastructure weighing on gas grid fees: AssessmentRegulatory measures that allow for faster recovery of capexFor the purposes of this analysis, we assume limited or no measures are taken. That said, it is clearly possible that Member States / NRAs may respond if faced with possible difficulties in recovering costs. The first-order impact of this measure would be higher network tariffs in the short run. However, this might allow future tariffs to be lower, thereby potentially reducing any competitive disadvantage relative to other energy carriers. The measure could also be combined with (temporary and partial) move of sunk cost recovery to other energy carriers / general taxation (see below), thereby avoiding overly discouraging gas use. To the extent use of gas might contribute to lower costs to society of the energy transition, this would therefore result in lower costs. The measure may give grid operators more certainty of ability to recover costs.The measure would involve a redistribution of costs from future gas consumers to current consumers (gas or potentially other fuels). Requires individual NRA decision only. The measure would require only an individual NRA decision to implement; the gains from co-ordinated EU action are not clear. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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221.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
 
 
 
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23Assessed solutions: Category 3 -Focus on natural gas in infrastructure regulationFocus on natural gas in infrastructure regulationClarity on access to infrastructureSolutions assessed from categories:Barrier category:Fit for purpose market design and charging arrangementsUncertain or inadequate quality standards3.1Providing improved visibility on gas quality for gas producers3.1.1Lack of (injection) charging methodology 3.2Incentive for grid operators to focus on gases compatible with their infrastructure3.3Lack of clear rules / compensation for interruption of gas injection3.4Uncertainty on the regulation of hydrogen (& other innovative gases) infrastructure3.5Clear rules on how quality is managed on an ongoing basis3.1.2Harmonised (distribution) injection charging rules across MS3.2.1Obligation on grid owners to connect renewable / low-carbon gases3.3.2Voluntary agreements to limit injections3.4.1Shorter-term markets for resolving locational congestion3.4.2Obligations to limit injections3.4.3Clarify whether Gas Directive rules apply to H2(and other gases)3.5.1 
 
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24There would be a cost involved in providing the information. However, developers would receive greater clarity on whether their investment can be accommodated by the grid, reducing the cost of capital, and therefore the costs of deploying renewable and low-carbon gases. Providing improved visibility on gas quality for gas producersReduces risk for developers.Consumers should ultimately benefit from lower costs of deployment Providing information would not necessarily be complex. However, limits (for example for hydrogen) would need to be established. Clarity on headroom in neigh-bouring TSOs/  DSOs reduces barriers to trade, though this may already be addressed (at least partially) by the inter-operability network code.Uncertain access to infrastructure due to uncertain or inadequate quality standards: assessmentInvestment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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25Clarity on the rules in place and compensation available can reduce risk to developers. By reducing the cost of capital, it potentially reduces the costs of deploying renewable and low-carbon gases.Clear rules on how quality is managed on ongoing basisGreater clarity could reduce risk for developers. However, players would need to have trust in the rules.Consumers should ultimately benefit from lower costs of deploymentRules could take time to design, and can only be implemented once limits have been established.Clarity on headroom in neigh-bouring TSOs/  DSOs reduces barriers to trade, though this may already be addressed (at least partially) by the inter-operability network code.Uncertain access to infrastructure due to uncertain or inadequate quality standards: assessmentInvestment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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26In the counterfactual, Member States may develop their own injection charging rules for renewable and low-carbon gases. The measure would Increase certainty for developers regarding how they might be charged for use of the gas grid. This may reduce the costs across the EU of deploying renewable and low-carbon gases, to the extent it reduces the associated risks to developers.  The extent to which the efficiency of decisions on where to invest is improved is uncertain, and depends on whether any change to the rules would improve the cost-reflectivity of tariffs. However, we assume that cost-reflectivity would not be worsened by the introduction of harmonised charging rules, compared to the counterfactual.Lack of injection charging methodology: AssessmentHarmonised (distribution) injection charging rules across EU MSImproved predictability of network charges could reduce risk to investors. . Overall, consumers across the EU should benefit from reduced costs of deploying renewable and low-carbon gases. Previous experience on network code development suggests the process of developing harmonised charging rules could be complex and time-consuming.Possible change to network codes (or new network codes) required. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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27In the counterfactual, Member States take (unspecified) steps to facilitate renewable gases and reduce barriers to access to the network. Depending on the measures already taken by Member States, a specific connection obligation could still lead to some increase in number or speed of deployment of renewable and low-carbon gas connections. The effect could be stronger for non-renewable gases, given these are not covered by the existing RED II text. If implemented in the transitional phase, this could result in a faster realisation of the benefits described under ‘R&D / pilots / deployment support + innovation incentives for network operators’. Incentive for grid operators to focus on gases compatible with their infrastructure: AssessmentObligation on grid owners to connect renewable / low-carbon gasesA specific connection obligation may reduced risk for developers.In the short-term,  consumers could end up paying more due to faster deployment of renewable and low-carbon gases,. However, the measure would contribute to the faster realisation of longer-term benefits.A robust framework for managing congestion and for managing issues related to gas quality (see slides 29-31) would need to be in place before an obligation to connect could be implemented. In addition, an obligation may not be meaningful in Member States that use shallow connection charging –as it may prevent higher-cost connections from being refused. Given the link to connection charging regime, it may be more appropriate for this decision to be left with Member States. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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28Interruptibility agreements would allow for players to signal the costs to them of selling capacity or reducing flows, helping to ensure lower-cost congestion management. However, it would not be as efficient as (real-time) market-based rules since players would not be able to signal any changes over time in the costs of helping to manage congestion. If used in conjunction with (real-time) market-based rules only, interruptible contracts could help to provide clearer longer-term signals regarding the value of flexibility. This in turn should also incentivise greater investment in flexibility, lowering long-run balancing costs.Lack of clear rules / compensation for interruption gas injection: AssessmentVoluntary agreements to limit injectionsCompensation means investors should not face additional risks.In the short term, (gas) consumers may bear an additional financial cost involved in providing compensation. However, over the long-run, lower congestion management costs should ultimately mean lower prices (unless there are localised market power issues meaning that players are able to require compensation substantially in excess of the cost to them of interrupting).The value of EU-wide co-ordination on measures to address congestion primarily focussed at distribution level is unclear, in particular given that cross-border part-icipation in congestion management is less likely to be relevant at distribution level. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesSuch agreements are relatively quick to implement.  
 
 
 
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29In the counterfactual, we assume Member States adopt non market-based rules, without compensation.The impact of market-based compensation would be to ensure that (in real time) measures with least cost to society are used to address localised congestion (note: this assumes that policy action has been taken to ensure that players internalise all wider costs or benefits they impose on the system). In the long-run, the possibility of compensation should also send signals for investment in greater flexibility. Lack of clear rules / compensation for interruption gas injection: AssessmentShorter-term markets for resolving locational congestionCompensation means investors should not face additional risks.In the short term, (gas) consumers may bear an additional financial cost involved in providing compensation. However, over the long-run, lower congestion management costs should ultimately mean lower prices (unless there are localised market power issues meaning that players are able to require compensation substantially in excess of the cost to them of interrupting).Market-based compensation could require changes to legislation to implement, and may be a more significant change in some Member States than in others (especially at distribution level).  The value of EU-wide co-ordination on measures to address congestion primarily focussed at distribution level is unclear, in particular given that cross-border part-icipation in congestion management is less likely to be relevant at distribution level. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
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30Lack of clear rules / compensation for interruption gas injection: AssessmentThe value of EU-wide co-ordination on measures to address congestion primarily focussed at distribution level is unclear, in particular given that cross-border part-icipation in congestion management is less likely to be relevant at distribution level. Interruptibility obligations would allow network operators to manage congestion, although there is no guarantee this would be done efficiently. Doing so would rely on the network operator having knowledge of the costs to individual operators of helping to manage congestion. This would be difficult to achieve without use of a market mechanism to reveal such costs. However, used in conjunction with the other congestion management options, making interruptibility mandatory could help reduce the costs to network operators of managing congestion if there are localised market power issues. In turn, this could increase the efficiency of congestion management (i.e. lower costs to society) if, in the counterfactual, the market power issues might have prevented the lowest cost congestion management options from being utilised by the network operator. There is a risk, however, that costs of investment increase as a result (see ‘Investment environment’).Obligations to limit injectionsMandating interruptibility runs the risk of deterring investment. Even if players receive remuneration, they may be unsure that the value of such remuneration will fully reflect the market value, for example if mandatory contracts are used even if there is limited market power. The overall effects are uncertain and are likely to depend on implementation. On the one hand, the measure could help to reduce costs to network operators and, in turn, to consumers if market power is important. On the other hand, there is a risk that the costs of deploying gases rise, due to increased risk borne by investors. These costs would be borne by consumers.  Avoiding the potential negative effects may require robust oversight by the NRAs, to ensure that mandatory contracts are not used unless there are market power issues. Similar provisions exist for electricity distribution operators in the revised Electricity Directive. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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31Increased clarity on the rules may help to reduce the risks for investors in networks, as well as providing increased clarity for developers of renewable and low-carbon gases regarding their ability to secure access to infrastructure. Overall, this should reduce the risks to investment, and in turn the costs of deploying renewable and low-carbon gases. Uncertainty on the regulation of hydrogen (& other innovative gases) infrastructure: AssessmentClarify whether Gas Directive rules apply to hydrogen (and other gases)Overall, increased clarity should reduce risks to investors. Any consumer benefits may accrue primarily to larger consumers (i.e. industrial) in the transition phase, as these are the players most likely to be using hydrogen networks. Agreeing on trigger points and treatment of investment carried out prior to the trigger point may prove complex. Time will be required to revise legislation. Changes in this area are likely to require revision to EU legislation. Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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321.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
 
 
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33Assessed solutions: Category 4 -Uncoupled and uncoordinated infrastructure planningUncoupled / uncoordinated infrastructure planningSolutions assessed from category:Barrier category:Co-ordinated infrastructure planning and decommissioningAssess optimal level of storage capacityCo-ordinated system planning between transmission and distributionRegulatory incentives to achieve system cost savingsCo-ordinated system planning across electricity and gasRisk that suitable storage will not be available4.1Insufficient co-ordination between distribution and transmission4.2Insufficient co-ordination between electricity and gas4.34.1.14.2.14.2.24.3.1 
 
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34Better understanding of the need for storage capacity in the future does not bring any direct benefits (and indeed there would be a cost associated with the assessment). However, having this understanding would help policy makers judge whether there is a risk that the current framework will not deliver sufficient storage (in particular the risk that storage may close prematurely from a societal perspective, given the difficulty in assessing future demand). This in turn would allow more informed choices to be made regarding possible further intervention on gas storage. That said, there is a risk (see ‘Investment environment’) that uncertainty for investors is increased. Risk that suitable storage will not be available: AssessmentAssess optimal level of storage capacityOn the one hand, investors may view the fact that some action is being taken to improve knowledge of the requirement for storage positively. On the other hand, there is a risk that even a limited intervention such as this may create an uncertainty regarding the nature of possible future policy or regulatory intervention on storage. Any potential action following on from the assessment might benefit consumers, either because it prevents storage from closing inefficiently or because it prevents storage from being kept open inefficiently. The assessment itself could be time-consuming, although not in itself a radical or controversial exercise. There is a strong link to existing EU infra-structure planning processes (such as the TYNDP process). In addition, storage may have benefits that spill across boundariesInvestment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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35Co-ordination may come at a cost to network operators. However, a common understanding on the range of potential scenarios in terms of gas supply and demand as well as a shared understanding of the different solutions across different levels of infrastructure could maximise the chance of an optimal system design (when combined with the right incentives –see next slide for more details). Insufficient co-ordination on future use of infrastructure (D vs T); implications for connections and infrastructure adaptation: AssessmentCo-ordinated system planning between transmission and distributionCo-ordinated planning would involve the development of a consistent geographic mapping of current and projected production and demand as a first step. This would allow operators to identify required investments. As such, the process of planning itself should not have direct impacts on investors. However, follow-on decisions (such as which investments are given regulatory approval) may affect investors (in different ways).Any reduction in the costs across the energy system (see ‘net societal costs and benefits’) arising indirectly from improved co-ordination of network planning should ultimately be reflected in lower costs to consumers. Benefits might be distributed differently, however, within Member States depending on the type of consumer (e.g. electricity only or both electricity and gas) and their location. It may be complicated and time-consuming to develop joint models, assumptions and ways of working if these did not exist previously. For example, currently according to Eurogas/CEDEC/GEODE, DSOs only have a clearly defined role in the scenario process in a few national grid development plans. The nature of T and D grid co-operation is likely to vary between MS. But there is still value to co-ordinated action at EU level, since (with increasing amounts of de-centralised production)issues at D-level could increasing-ly spill over to other MS.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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36Insufficient co-ordination on future use of infrastructure (D vs T); implications for connections and infrastructure adaptation: AssessmentThe nature of T and D grid co-operation is likely to vary between MS. But potentially still value to co-ordinated action at EU level since issues at D-level could increasing-ly spill over to other MS.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesIn the counterfactual, TSOs and DSOs (in some Member States) may focus primarily on their respective infrastructure, leading to inefficient investment decisions from society’s perspective. Effective incentives could reduce the costs to society of investing in/operating gas infrastructure. However, the extent to which incentives might be effective is uncertain (see ‘Complexity’). Regulatory incentives to achieve cost savingsSuch incentives could be perceived negatively by individual network operators, for example if there was a risk it might mean a lower RAB value.Lower costs to society should ultimately be reflected in lower costs to consumers. There is a risk of unintended consequences from new types of regulatory incentives, in particular the risk of (creating unforeseen) perverse incentives for network operators.In addition, there is a risk that NRAs suffer from information asymmetry, making it difficult for them to judge when savings have been truly made. Information gained through co-ordinated planning and CBA may offset this to some extent. 
 
 
 
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37Insufficient co-ordination on future use of transmission infrastructure electricity vs gas –and aligned operator incentives: AssessmentCo-ordination may come at a cost to network operators. However, a common understanding on the range of potential scenarios in terms of gas supply and demand as well as a shared understanding of the different solutions across different levels of infrastructure could maximise the chance of an optimal system design (when combined with the right incentives –see next slide for more details). Co-ordinated system planning across electricity and gasThe process of co-ordinated planning itself should not have direct impacts on investors. However, follow-on decisions (such as which investments are given regulatory approval) may affect investors (in different ways).Overall, there should be benefits to EU consumers from reduced expenditure on infrastructure. However, the benefits might potentially be distributed differently between electricity and gas customers (and perhaps also between Member States)The ENTSOs already developed joint scenarios intended to capture relevant interlinkages between the electricity and gas sectors. As part of this process, the ENTSOs are also developing an interlinked electricity and gas model. This model will eventually be used to support cost-benefit analysis of relevant projects. Further work may be required to ensure greater co-ordination between energy network operators at national level. Planning in one Member State, particular-ly of intercon-nection or assets used primarily for transit is likely to have impli-cations for other Member States.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
 
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38Insufficient co-ordination on future use of transmission infrastructure electricity vs gas –and aligned operator incentives: AssessmentPlanning in one Member State, particular-ly of intercon-nection or assets used primarily for transit is likely to have impli-cations for other Member States.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelinesIn the counterfactual, electricity and gas TSOs may focus primarily on their respective infrastructure, leading to inefficient investment decisions from society’s perspective. Effective incentives could reduce the costs to society of investing in/operating gas infrastructure. However, the extent to which incentives might be effective is uncertain (see ‘Complexity’).Regulatory incentives to achieve cost savingsSuch incentives could be perceived negatively by individual network operators, for example if there was a risk it might mean a lower RAB value.Overall, there should be benefits to EU consumers from reduced expenditure on infrastructure. However, the benefits might potentially be distributed differently between electricity and gas customers (and perhaps also between Member States)There is a risk of unintended consequences from new types of regulatory incentives, in particular the risk of (creating unforeseen) perverse incentives for network operators.In addition, there is a risk that NRAs suffer from information asymmetry, making it difficult for them to judge when savings have been truly made. Information gained through co-ordinated planning and CBA may offset this to some extent.  
 
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391.Solutions assessment methodology22.Solutions: Category 1 -Relative immaturity of sector coupling and renewable gases technologies43.Solutions: Category 2 -Unlevel playing field due to sector and technology-specific tariffs and levies134.Solutions: Category 3 -Focus on natural gas in infrastructure regulation225.Solutions: Category 4 -Uncoupled and uncoordinated infrastructure planning326.Solutions: Category 5 -Risks for interoperability across markets and borders39 
 
 
 
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40Assessed solutions: Category 5 -Risks for interoperability across markets and bordersRisk for interoperability across markets and bordersCo-ordinated infrastructure planning and decommissioningSolutions assessed from category:Barrier category:Risk of lack of liquid market for sale of heterogenous gasesLack of coherent cross-border framework for decommissioningLiquidity impacts to be considered in infrastructure planningFramework for co-ordinated cross-border decommissioning5.3.15.35.5.15.5 
 
 
 
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41In the counterfactual, potential liquidity impacts would not be considered systematically in CBAs carried out to evaluate infrastructure investment, conversion and decommissioning decisions. Some decisions (e.g. decommissioning / H2 conversions) may fragment the gas market geographically or by product. Given that liquidity can have impacts on costs of trading as well as on the cost of investment (by affecting the offtake and revenue risk faced by participants), the lack of systematic consideration of liquidity impacts could lead to inefficient decision-making due to an incomplete CBA methodology. More systematic consideration of liquidity impacts could therefore lead to lower costs overall from a societal perspective.Risk of lack of liquid market for sale of heterogenous gases: AssessmentLiquidity impacts to be considered in infrastructure planningTo the extent that this assessment indirectly contributes to better future liquidity, it reduces risks to market participants. Consumers overall should benefit from reduced costs in the energy system. Considering liquidity impacts would require updates to CBA methodologies, but it is unclear whether legislative changes would be required to achieve this. Modelling liquidity impacts may also be complex and subject to uncertainty Impacts of decisions in one MS could spill over to other MS. A standard-ised approach to assessing liquidity impacts  would be important in ensuring con-sistency.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
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42In the counterfactual, Member States may take unilateral decisions to decommission gas infrastructure that could be delivering benefits in other Member States.Co-ordinated cross-border decommissioning may therefore lead to avoided or delayed decommissioning in such cases. Overall, from an EU-wide perspective, costs to society should be lower as a result. However, in such cases, the savings in resource costs are distributed differently between Member States. Those that were planning to decommission may face increased costs (they may avoid decommissioning costs but would continue to incur opex). Other Member States may benefit from increased security of supply and/or reduced costs of gas supply or avoided costs of switching to alternatives to gas.Lack of coherent cross-border framework for decommissioning: AssessmentFramework for co-ordinated cross-border decom-missioningCross-border cost allocation provides greater reassurance for infrastructure owners around the financing base. Cross-border cost allocation methodology provides a means of ensuring that consumers are no worse off as a result. May require change to EU regulation (TEN-E). Could take 2-3 years for consultation/ adoption and then time for ENTSOG to develop CBA methodology. There is a clear EU-wide benefit to co-ordination between Member States on this issue.Investment environmentConsumer protectionNet societal costs and benefitsEU value-addedComplexity and timelines 
 
 
 
 
 
 
 
 
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